Process and apparatus for converting oil shale or oil sand (tar sand) to oil

ABSTRACT

The disclosed invention is a process for producing synthetic crude oil and includes embodiments which convert or upgrade oil bitumen, a combination of oil sands and bitumen, a combination of sand and bitumen, oil shale and kerogen to high grade low sulfur crude oil. In one embodiment it is a continuous process for producing synthetic crude oil from oil sand bitumen. In another it produces synthetic crude oil from oil shale. The process in one embodiment includes a fluid bed reactor where the reactant and fluidizing medium is substantially hydrogen. In other embodiments, the process includes treating the oil sand (tar sand) or shale to produce a fluidizable feed, feeding the fluidizable feed to a fluidized bed reactor, and fluidizing and reacting the fluidizable feed in the fluidized bed reactor with a feed having hydrogen.

FIELD OF THE INVENTION

The present invention relates to a continuous process for producingsynthetic crude oil (SCO) from oil shale or oil sand (also known as “tarsand”) and an apparatus for its practice. More specifically, the presentinvention provides a process for treating dry oil sand (tar sand) orshale without prior beneficiation, in a reactor operating at elevatedpressure and temperature conditions, in the presence of hydrogen gas.The invention also relates to a continuous process for producing SCOfrom oil sand bitumen. The processed bitumen can be extracted from underground via in situ processes, or strip mined and extracted via hot waterextraction processes. The present invention, can also produce SCO fromoil shale. Raw kerogen oil can be extracted in situ from shaleunderground.

The invention can be used to convert, process or upgrade one or more ofbitumen, oil sand, oil shale, kerogen oil and heavy hydrocarbonfeedstocks to synthetic crude oil.

BACKGROUND OF THE INVENTION

Oil sand (tar sand) systems are known for making synthetic crude oil(SCO), such as those that surface mine and process the oil sand (tarsand), where they first separate sand (85 wt. %) from bitumen (11 wt. %)to avoid processing the sand in the reaction systems. The separatedbitumen is converted to sweet, light crude oil by an upgrading refineryoperation. Separation of the sand from the bitumen requiresbeneficiating operations such as floatation cells and secondaryseparation equipment and processing and equipment to prepare the oilsand (tar sand) for flotation. In these systems, tailing oil recovery isnecessary to clear the sand for disposal, however the sand is notcompletely cleared of bitumen.

Existing technology uses a large number of physical and chemicalprocessing units for the treatment of wet oil sand (tar sand), e.g.,tumblers (being phased out by hydro-pumping), beneficiators including:primary separation vessels with floatation cells and secondaryseparation systems necessary to recover the bitumen from the oil sand(tar sand); tailing oil recovery systems which result from the sand notbeing completely cleared of bitumen; tailing settling ponds which arenecessary to settle and separate fine clays and other undesirable solidsfrom the water for floatation since the water must be reused to maximizeclean-up to reduce environmental problems. These systems can be largefacilities along with the maintenance and systems for reclaimation.

Raw oil sand (tar sand) can be treated in a fluidized bed reactor in thepresence of a reducing environment, steam, recycle gases and combustiongases.

BRIEF SUMMARY OF THE INVENTION

The process and apparatus of the present invention avoid the use of thelarge number of physical and chemical processing units used in theprocessing of wet oil sand (tar sand) by using a single continuousreactor system to hydrocrack and hydrogenate the dry oil sand (tarsand). Moreover, because the present invention directly hydrogenates dryoil sand (tar sand), larger quantities of valuable sweet, light crudeoil are obtained. Moreover, with the present invention, less gas andsubstantially no coke are produced.

The present invention relates to a continuous process for converting oilbearing material, e.g., oil shale or oil sand (tar sand), and anapparatus for its practice.

One embodiment of the present invention provides a continuous processand an apparatus for its practice where oil bearing material such as thekerogen in oil shale or the bitumen in oil sand (tar sand) iscontinuously treated.

In one embodiment, the present invention relates to the treatment of dryoil sand (tar sand).

In one embodiment, the present invention provides a method and apparatusfor converting a oil sand (tar sand) or shale feed to oil which can beconducted in the absence of a beneficiation processes such as, forexample, a hot-water extraction process to separate sand or other nonreacting solids from bituminous or oil-bearing material in the feed.

In one embodiment, the present invention provides a process forconverting oil sand (tar sand) to oil through the use of a streamcontaining hydrogen in a concentration greater than 90 vol % (90 vol%-100 vol % H2).

In one embodiment, the present invention provides a heat recoveryprocess whereby hydrogen provides the heat necessary to bring the rawoil sand (tar sand) up to reactor temperature.

In one embodiment, the present invention provides a process wherehydrogen is used for hydrocracking and hydrogenating the bitumen in theoil sand (tar sand) or oil shale.

In one embodiment, the present invention provides a process for usingrecycle and make-up hydrogen as a heat transfer vehicle.

In one embodiment, the present invention provides an improved processfor producing oil from oil sand (tar sand) or shale by reacting the oilsand (tar sand) or shale with a stream containing hydrogen in aconcentration greater than 90 vol % (90 vol %-100 vol % H2) in afluidized bed reactor, wherein the fluidizing medium is a feed streamincluding hydrogen gas.

In one embodiment, the present invention provides a fluidized bedprocess where one inch or less size oil sand (tar sand) or shale piecesare fed into a fluidized bed reactor near the bottom of the reactor andspent sand and reaction products are removed from near the top of thereactor.

In each of the following three embodiments:

-   -   Extraction produced bitumen and raw sand or tailings pond sand;        or    -   in situ produced bitumen and raw sand or tailings pond sand; or    -   in situ produced raw kerogen oil and shale,        are fed to the reactor via the lock-hopper system for solids and        injection lines for liquids.

In one embodiment, the present invention provides a method of recyclingunreacted hydrogen that exits a reactor in which oil sand (tar sand) oroil shale is converted to oil. The method includes purging impurities inthe exiting recycle hydrogen stream by pressure swing adsorption,maintaining the hydrogen at more than about 450 psig throughout therecycle process, admixing fresh hydrogen to the recycle hydrogen streamto form a mixture, and feeding the mixture into the reactor.

In one embodiment, the invention is provides a process for producing oilfrom an oil bearing feed such as oil sand (tar sand) or oil shale. Theprocess comprises introducing the feed in a fluidizable form into afluidized bed reactor. A fluidizing medium enters the fluidized bedreactor where it contacts and fluidizes the fluidizable feed. Thefluidizing medium includes at least hydrogen. The fluidized feed forms afluidized bed where the feed reacts with the hydrogen provided by a feedstream having hydrogen in a concentration of from 90-100% at atemperature within the equipment design range of about 800° F. to about1500° F., with one embodiment having a reaction temperature of 900°F.-1200° F., and another embodiment having a reaction temperature ofabout 915° F. The reaction products include synthetic crude oil andspent solids which are discharged from the fluidized bed reactor.

In one embodiment, the invention provides flexibility in the processingof feedstocks. It comprises a process for upgrading oil bearing materiale.g. bitumen or kerogen, and an apparatus for its practice.

In one embodiment, the present invention provides a continuous processand an apparatus for its practice where oil bearing material such as thekerogen from oil shale or the bitumen in oil sand is continuouslytreated.

In one embodiment, the present invention provides a process forupgrading extracted bitumen, or in situ produced bitumen or kerogen,through the use of a stream containing hydrogen in a concentrationgreater than 90 vol % (90 vol %-100 vol % H2).

In one embodiment, the present invention provides the heat necessary tobring the bitumen or kerogen up to reactor temperature of about 800°F.-1500° F.

In one embodiment, the present invention provides the heat necessary tobring tailings or raw sand up to a temperature in the range of 840°F.-1000° F., with one embodiment having a temperature of about 915° F.for the fluid bed reactor for processing the bitumen or kerogen.

In one embodiment, present invention provides a process where hydrogenis used for hydrocracking and hydrogenating the bitumen of an oil sandor a kerogen of oil shale.

In one embodiment, the present invention provides a process for usingrecycle and makeup hydrogen as a heat transfer medium.

In one embodiment, the present invention provides an improved processfor producing upgraded oil from extracted bitumen or in situ producedbitumen or kerogen, wherein the fluidizing medium is substantiallyhydrogen.

In one embodiment, the present invention provides an improved processfor producing upgraded oil from extraction produced bitumen or in situproduced bitumen, or in situ produced kerogen from shale where raw sandor tailings sand or shale respectively is fed into the bottom of thereactor for fluidization with hydrogen and the reaction products aredischarged from near the top of the reactor.

In one embodiment, the present invention provides a method for recyclingthe excess unreacted hydrogen from the reactor in which bitumen orkerogen is upgraded to high grade low sulfur oil (about 0.1 to 0.5 wt. %sulfur, or less). In the processing of oil sands and bitumen, this canproduce an SCO having an API gravity of 280 to 34° and a sulfur contentof about 0.1 to 0.5 wt. %. In the case of processing oil shale a lighterproduct is produced ranging from 280 API to as high as 40° API or more.

In one embodiment, the present invention provides the dry fluidized bedof sand in a reactor at a temperature of about 900° F. and 600 psig toreceive hot bitumen at about 300° F. in a steam-traced line from aconventional, or existing, extraction facility, such as a hot bitumenextraction plant. Sand from existing sand tailings deposits oroperations can be transported to the reactor by conventional, orexisting, materials handling means. In one embodiment, sand fromtailings deposits can be transported to the plant by trucks orhydrotransport as a slurry, dewatered and handled by conveyors, bucketelevators, screened and fed to the reactor.

In one embodiment, the present invention provides a process forprocessing the reclaimed sand and extracted bitumen together in thepreviously discussed reactor to produce a higher grade, about 34° API,low sulfur oil of about 0.1 to 0.5 wt. % sulfur, or less, by the use ofan appropriate catalyst.

In one embodiment, the invention processes in situ produced hot bitumenin a fluid bed reactor located in close proximity to the producing wellhead. Reclaimed sand is fed in a continuous stream to the reactor toprovide the fluid bed medium in addition to the hot bitumen which is fedseparately. Recycle and make-up hydrogen pre-heated to about 1500° F. ina central fired heater provide the reactant, fluidizing medium and heatconveyor for the reactor which is operated at about 900° F. and 600psig. The reclaimed sand can be transported to the site as a waterslurry and be dewatered. Spent sand from the reactor containing somecoke from the reaction process can then be slurried with the originalincoming water and be transported back to its original or an alternatearea for disposal.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows the flow diagram of one embodiment according to the presentinvention.

FIG. 2 shows a fluidized bed reactor for converting bitumen in oil sand(tar sand) to viable products in accordance with the present invention.

FIG. 3 shows a stand-alone fired heater used in the process according tothe present invention.

FIG. 4 shows a compressor for supplying the hydrogen for use in thepresent invention.

FIG. 5 shows the flow chart of an acid gas recovery system for use inthe present invention.

FIG. 6 shows the mass balance for one embodiment of the presentinvention.

FIG. 7-1 shows a flow diagram of a second embodiment according to thepresent invention.

FIG. 7-2 shows a flow diagram of turbine, product separation and aminesystem of the second embodiment.

FIG. 7-3 shows a flow diagram of a variety of optional feed streams.

FIG. 7-4 shows a flow diagram of a reactor operations embodiment.

FIG. 7-5 shows a flow diagram of and embodiment of turbine, productseparation and amine system.

FIG. 8 shows a fluidized bed reactor embodiment with lock hoppers.

FIG. 9 shows a process flow diagram for Example 3

In FIGS. 1-6, common elements are similarly identified except for the“figure number” designation. Thus, all elements depicted in FIG. 1,start off with the number 1, e.g., the reactor in FIG. 1 is identifiedas “104” and in FIG. 2 the same reactor is identified as “204.”

DETAILED DESCRIPTION OF THE INVENTION

In one embodiment of the invention hydrocarbon bearing solids, e.g., dryoil sand (tar sand) or oil shale is processed in a fluidized bedreactor. Reaction occurs in the reactor as the feed constituents undergoreactions, including reactions with hydrogen. The process is operated insome embodiments to avoid decompression of the hydrogen. A first portionof a stream containing hydrogen in a concentration greater than 90 vol %(90 vol %-100 vol % H2) is used to feed the oil shale or oil sand (tarsand), which has been comminuted and reduced in size to form particlesthat are capable of being fluidized, e.g., fluidizable, into thereactor. A second portion of the hydrogen stream is used as thefluidizing medium.

The concentration of a hydrogen feed can vary in this invention. Oneembodiment utilizes pure hydrogen feed (100% H₂). Most embodiments uselower purity hydrogen because light hydrocarbons are formed in thereactor, i.e. methane and ethane, the accumulation of these light gasesadversely affects the reaction between bitumen and hydrogen bysuppressing the partial vapor pressure of the hydrogen. A recyclehydrogen stream is therefore operated in another embodiment to maintainthe hydrogen concentration at about 94 vol. % by purging methane andethane via the PSA system. The invention can use hydrogen feedconcentration as low as 25 vol. %, or lower.

While the reactor can react with any concentration of hydrogen in thefeed stream (I vol %-100 vol % H₂). Some embodiments use hydrogen feedstreams with H₂ concentrations of 75 vol %-94 vol % and methane andethane concentrations of 6 vol % to 25 vol %. One embodiment utilizes ahydrogen feed stream having 94 vol % H₂ and 6 vol % methane and ethanemixture.

In one embodiment, the hydrogen stream that feeds the reactor is formedfrom fresh make-up hydrogen and recycle hydrogen generated during theprocess, or obtained from other hydrogen producing processes. A mixedstream of fresh-make-up and recycle hydrogen stream is discharged from acompressor at a first temperature and pressure (e.g., 187° F. and 670psig), and a portion is diverted for admixture with the fluidizableparticles of oil sand (tar sand) or oil shale which are injected intothe fluidized bed reactor in a fan like flow, at an acute angle relativeto the vertical axis of the reactor or a horizontal plane.

The reference to fan like flow supra is further described in conjunctionwith an embodiment where the solids (e.g., oil sands, oil shale,ordinary sand or failings pond sand) are fed to the reactor in a flow bya combination of gravity and assistance from the high pressure hydrogenmotivation stream into the reactor. The inlet line from the lock-hoppersystem to the reactor can be horizontal or can be inclined relative tothe vertical axis of the reactor. Mechanical means such as a screw canbe used in certain applications to assist the solids flow into thereactor. The highly agitated conditions in the reactor quickly dispersethe solids feed into the fluidized bed. One embodiment utilizes fourlock-hopper feed systems which can be equally spaced around thecircumference of each reactor.

In one embodiment, the solids fed to the reactor, either oil sands, oilshale, ordinary sand or tailings pond sand, flow by a combination ofgravity and assistance from the high pressure hydrogen motivation streaminto the reactor. The actual inlet line from the lock-hopper system tothe reactor can be horizontal or can be inclined relative to thevertical axis of the reactor. Mechanical means such as a screw can beused in certain applications to assist the solids flow into the reactor.The highly agitated conditions in the reactor quickly disperse thesolids feed into the fluidized bed. Our present design provides fourlock-hopper feed systems equally spaced around the circumference of eachreactor.

The remainder of the hydrogen stream at said first temperature isindirectly heated to a second higher temperature by indirect heatexchange with overhead products from the fluidized bed reactor. Thesecond higher temperature is the temperature of the hydrogen stream fromthe discharge of the compressor that has passed through the in-out heatexchanger in order to cool the reactor over head stream. It can be about875° F.; having been heated from 187° F. by indirect heat exchange withhot reactor over head stream. Indirect simply means the heat transferfrom a hotter gas to a cooler gas takes place through a solid metallicretaining wall so that mixing of the two gas streams cannot occur.

The hydrogen stream at the second temperature (e.g., about 875° F.) isconveyed to a direct fired heater where the hydrogen stream is heated toa third temperature higher than said second temperature (e.g., about1200° F.-1500° F.) and then used as the fluidizing medium in the reactorto fluidize the oil sand (tar sand) or oil shale fluidizable particlesthat have been injected with the first portion of the hydrogen stream.

In the fluidized bed reactor the bitumen in the oil sand (tar sand), orthe kerogen in the oil shale change phase and can be reacted viaendothermic and exothermic reactions, including reactions with hydrogen,to produce spent oil sand (tar sand) or oil shale and an overheadproduct stream that contains hydrogen, hydrogen sulfide, sulfur gases,C₁+C₂ hydrocarbons, ammonia, fines (sand particles and clay) andvaporous products. The overhead product stream is first separated incyclone separators within the reactor which help maintain the bed leveland separate solids.

The reaction products formed in the reactor that upon cooling,condensing and separation from the other stream components form theliquid product SCO. In the liquid phase these products are grouped asnaphtha, distillate and gas oil.

In the reactor, contact between the feeds and hydrogen takes placewithin the fluidized bed of raw sand, or tailings pond sand or shale.The particular solid being fed, either raw sand, tailings pond sand orshale, establishes the fluid bed for the particular combination of feedstocks being processed. The reaction between hydrogen and bitumen orbetween hydrogen and raw kerogen oil produces reaction products ingaseous or vapor form. Also, the water contained in oil sands, raw sandsor tailings pond sand fed to the reactor vaporizes to form steam. Theproduct and water vapors exit the reactor via the normal flow patternthrough the internal cyclone separators at the top of the reactor andflow downstream to the next stage in the process circuit.

The solids fed to the reactor, either oil sands, oil shale, ordinarysand or tailings pond sand, flow by a combination of gravity andassistance from the high pressure hydrogen motivation stream into thereactor. The actual inlet line from the lock-hopper system to thereactor can be horizontal or can be inclined relative to the verticalaxis of the reactor. Mechanical means such as a screw can be used incertain applications to assist the solids flow into the reactor. Thehighly agitated conditions in the reactor quickly disperse the solidsfeed into the fluidized bed. Our present design provides fourlock-hopper feed systems equally spaced around the circumference of eachreactor.

In one embodiment, the overhead product stream is first separated fromthe fluid bed solids by the reactor space above the level of the solidsby the reactor space above the level of the solids overflow line and theinternal cyclone separators. (The bed level can be established by the bythe height of the solids overflow lines above the reactor support grid).

The reactor effluent stream of gases and product vapors separated frommost of the reactor sand and shale can be considered the “Firstseparated overhead” product.

The first separated overhead product is conveyed to a hot gas filter(s)to provide a cleaned product stream. The hot gas filter can removeunstrained sand, shale or fines that escape from the reactor andcleanses that hot overhead stream. In one embodiment, the temperature ofthe product overhead stream after the hot gas filter is about 915° F.but can range 840° to 1000° F. The cleaned product stream at a firsttemperature (e.g., 840° to 1000° F.) is conveyed to a first heatexchange unit where heat is transferred to a second portion of thehydrogen stream and results in a product stream at a second temperaturelower than said first product stream temperature (e.g., about 450° F.).The second portion hydrogen stream can constitute a recycle and make-uphydrogen stream which can be fed to the fired heater and to the reactor.The second temperature lower than said first product stream temperatureof the recycle stream (second portion) is in one embodiment thetemperature of the overhead product stream after the in-out heatexchanger, which for one embodiment is about 450° F. which is lower than915° F., the normal temperature before the in-out heat exchanger. Thissecond temperature can however vary (300° F. to 900° F.).

The product stream at said second temperature is conveyed to a condenserto further reduce its temperature to a third temperature lower than thesecond product stream temperature which in one embodiment can be cooledin a range of about 100° F. to about 450°. The overhead gas stream canbe cooled to 100° F. from about 450° F. to condense the product vapors.In some embodiments additional heat recovery can take place between thein-out heat exchanger and the condenser. This can result in a lowertemperature of the gas stream going to the condenser, perhaps as low as200° F.

The product stream at said third temperature contains liquid and gasfractions and is conveyed to a separator where the gas fraction isremoved, sent to an amine scrubber, and recycled as a scrubbed recyclehydrogen stream, and the liquid fraction is removed as oil product(SCO).

The recycle hydrogen is conveyed to a compressor where it is combinedwith fresh make-up hydrogen for use in the fluidized bed reactor as thefirst and second hydrogen stream portions.

The following definitions are employed in this disclosure.

“Bitumen” Bitumen is a naturally occurring petroleum-based tar-likematerial. It is the hydrocarbon component found in tar or oil sands.Bitumen, the hydrocarbon component found in oil sands, varies incomposition depending upon the degree of loss of the more volatilecomponents. It can vary from a very viscous, tar-like, semi-solidmaterial to solid forms. The hydrocarbon types found in bitumen comprisealiphatics, aromatics, resins, and asphaltenes. A typical bitumenhydrocarbon might be composed of:

-   -   19 wt. % aliphatics (which can range from 5 wt. %-30 wt. %, or        higher)    -   30 wt. % aromatics (which can range from 15 wt. %-50 wt. %, or        higher)    -   32 wt. % resins (which can range from 15 wt. %-50 wt. %, or        higher)    -   19 wt. % asphaltenes (which can range from 5 wt. %-30 wt. %, or        higher)        Sulfur content of bitumen can range in excess of 7 wt. %.

In addition bitumen can contain some water and nitrogen compoundsranging from less than 0.4 wt. % to in excess of 0.7 wt. %. The metalscontent, while small, must be removed to avoid contamination of theproduct SCO. Nickel can vary from less than 75 ppm (part per million) tomore than 200 ppm. Vanadium can range from less than 200 ppm to morethan 500 ppm.

The percentage of the hydrocarbon types found in bitumen can vary. Forexample, asphaltenes can vary from 10 wt % to 20 wt %.

“Catalyst” The definition of catalyst as used in the chemical industryis that it is a substance that initiates or accelerates a chemicalreaction without itself being affected. The term “catalyst” encompassespure, diluted, blended, mixed catalysts and catalysts provided on asupport material, or by coating, impregnating and the like. Catalyst canbe added directly to the oil sand feed stream and thus carried into thereactor where the reaction between hydrogen and bitumen and itscomponents is promoted. Catalyst can also be utilized in thehydrotreater where the reactions between hydrogen and sulfur, nitrogen,complex aromatics, etc. is promoted and these contaminants can then beremoved from the product stream. Catalysts for these purposes areusually formulated by the catalyst manufacturer to suit the requirementsof the feed stock being processed. The invention can utilize a broadvariety of catalysts including those having metals and can includeelements such as nickel, cobalt, molybdenum, iron, and aluminum.

“Degrees API” The American Petroleum Institute, the United States Bureauof Mines and the National Institute of Standards and Technology selectedthe API scale in 1921 as the standard for petroleum products in theUnited States. It is an arbitrary scale but is accepted widelyinternationally in the petroleum industry as it provides a measure ofthe density of the liquid being described.${{Degrees}\quad{API}} = {\frac{141.5}{{Specific}\quad{gravity}\quad 60{^\circ}\quad{F/60}{^\circ}\quad F} - 131.5}$The above shows the relationship between degrees API and specificgravity. For example, if a substance had a specific gravity of 0.0 at60° F. with reference to water at 60° F., solving the equation wouldgive it an API gravity of 45.4°.

“High grade” or “excellent quality” oil sands contain 12% bitumen orhigher.

“Low grade” is the opposite of high grade. The subject matter is ofinferior or poor quality. For example, oil sands containing about 6-9wt. % bitumen would be considered low grade; 9-11 wt. % bitumen oilsands would be average grade and 11 wt. % plus bitumen oil sands wouldbe considered high grade. High grade product oil (SCO) would be a lowsulfur (about 0.1 to 0.5 wt. % sulfur, or less), light crude oilpossessing excellent qualities for further processing.

“Low Grade Oil Shale” can be shale that yields very little shale oilwhen processed. Since the kerogen in oil shale is a sold and cannot beextracted without a change in at least one of form, physical propertiesor phase, as for example, bitumen is extracted from oil sands, thequality or grade of oil shale can be measured by the amount of shale oilthat is produced when conversion of the kerogen in the shale takesplace. Oil shale producing less than about 15 gal/ton of shale oil isconsidered low grade.

“In-situ” production methods are used on bitumen deposits buried toodeep for mining to be economical. The bitumen can be recovered byseveral means, including steam assisted gravity drainage (SAGD). In-situproduction of bitumen means production takes place at its original site.

“In situ oil Sand” is oil sand which is in its original location, or oilsand which has not been chemically modified, reacted or mixed so as tolose its original chemical properties.

“In situ kerogen” is kerogen which is in its original location, orkerogen which has not been chemically modified, reacted or mixed so asto lose its original chemical properties. Additionally, In situ kerogenrefers to kerogen contained in shale that is in its natural originalsite. The shale is in place, not having been mined or otherwiserelocated. In situ production of kerogen requires it to be convertedfrom a solid to a condensable vapor at its original site and this vaporwhen recovered and condensed becomes liquid shale oil.

“In situ Shale” shale which is in its original location, or shale whichhas not been chemically modified, reacted or mixed so as to lose itstypical properties. In one embodiment oil shale contains water in arange of about 1 wt % to 7 wt %. The water concentration of shale can behigher (e.g., 10-15%) depending on the source.

“Kerogen” is a bituminous material in shale that yields oil (“kerogenoil”) upon heating. When kerogen is heated to temperatures over 700° F.,it decomposes to produce a liquid oil similar to petroleum. i.e.,naturally occurring erode oil. Unlike the bitumen contained in oilsands, the kerogen in oil shale is a solid that does not melt and isinsoluble. To exploit it, kerogen must be converted from a solid to anon-solid state. This is accomplished by heating the kerogen containingoil shale to about 900° F. in the absence of oxygen to convert thekerogen to a condensable vapor which upon cooling becomes liquid shaleoil or raw kerogen oil.

“Mesh”—In coarser sizes of screens, the term “mesh” means the distancebetween adjacent wives or rods. In the finer sizes of screen cloths themesh means the number of openings per linear inch of screen.

“Oil shale”—Oil shales are fine grained sedimentary rocks containingrelatively large amounts of organic matter from which significantamounts of shale oil can be extracted. Oil shale is a fine crained,calcareous rock containing kerogen, a solid hydrocarbon.

“Pressure” as used herein, the term pressure refers to the force actingper unit area within the various vessels and pipelines constituting ourprocess plant. It is expressed as pounds per square inch (psig). Allreferences herein to pressure are in units of pounds per square inchgage, psig, unless otherwise indicated.

“Sand” as used herein, unless otherwise specified, “sand” as a feedstockencompasses all types of sand either alone or in combination: e.g.,sand, raw sand, tailings sand, reclaimed sand, spent sand, supplementalsand and ordinary sand.

“Raw Sand” is ordinary silica sand mined from sources other thantailings ponds. An embodiment provides the fluid bed medium in thereactor. The fluidized bed of sand provides much surface area promotingcontact and reaction between hydrogen and injected liquid bitumen.

“Reclaimed sand”—This term refers to sand recovered from current wetextraction operations directly from the process operations or from thesettling ponds following the relatively rapid settling out of the coarsesand.

“Run of Mine” is the term applied to oil sand and shale mined before anyprocessing or beneficiation takes place. The oil sands are “as mined”,dug from the pit and loaded onto trucks or other conveying equipment.

“SAGD” (steam assisted gravity drainage) refers to steam assistedgravity drainage method of bitumen extraction or production. Thisproduction method can apply to reserves too deep to be minedeconomically. In SAGD production, parallel horizontal wells are sunkinto a reserve. One well injects steam to heat the surrounding oil sandsand reduce the viscosity of the bitumen. A second, lower well extractsthe bitumen as it flows by gravity to the production well.

“Wet extraction” refers to the current industry process of bitumenextraction using hot water as the main processing medium. Advances havebeen made since the early days when very hot water was used. Today, acombination of chemicals addition and lower water temperature of about120° F. are being used but current mining operations using waterextraction can be described as wet extraction methods.

“Tailings”—The term tailings as used herein refers to the refusematerial comprising sand, clay traces of bitumen, etc. remaining afterthe bitumen has been extracted from oil sands. This material isdiscarded by the process as a water slurry into tailings ponds where theheavier sand settles to the bottom of the pond. The problem withtailings ponds is that the finer clay particles remain in suspension fora long period taking years to settle and consolidate.

“Oil sand” and “Tar Sand”—These terms are used synonymouslyinterchangeably but modern industry usage more commonly recites “oilsand”. Oil sand (tar sand) contains the heavier asphaltic components ofpetroleum. It can be considered the end product of evaporation ofpetroleum's volatile components. Tar sand or oil sand is a combinationof clay, sand, water and bitumen. It is sand whose intertices remainsfilled with asphalt after lighter portions of crude oil have escaped;Tar or oil sands as found in nature consist of particles or grains ofsand, each grain being surrounded with a film of water upon which a filmof bitumen, a dark, asphalt like oil is deposited. The bitumen contentof oil sands can vary broadly from less than 1 wt. % to as high as 20wt. %. The average bitumen content of oil sands below about 7-8 wt. %bitumen are currently considered to be of low quality.

“Upgrading” is a term used to refer to the treatment of crude oil toimprove its quality. As used in our process the main product ofupgrading is synthesized crude oil that can be later refined like(conventional) natural erode oil into a broad range of products. It isthe conversion of bitumen from a viscous, tar-like substance into a highquality, light sweet crude oil with no residual bottoms. Upgrading isthe process of converting heavy oil or bitumen into synthetic crude oil.The process converts bitumen which can have an API gravity of 8-10° toan SCO of 30-34° API. In the process, heavy long chain hydrocarbons arebroken down or cracked into lighter short chain hydrocarbons sulfur andnitrogen compounds are converted to hydrogen sulfide and ammonia andremoved. Also, metals such as nickel and vanadium can be removed in theprocess. One objective of upgrading is to reduce the viscosity of theoil and control the amount of solids and water. The full upgradingprocess reduces sulfur, nitrogen and metals content to produce a crudeoil substitute of high quality that can be refined by current commercialrefinery operations.

“Feedstock” and “feed” refer to a material which enters a unit operationor process. In the invention a variety of deedstocks are processed toproduce products including SCO. For example, the reactor feed system inone embodiment can provide both solid and liquid feedstocks (feeds) tothe reactor. Feedstocks feeds can be fed to a unit operation or processseparately or in mixtures with other materials and feeds. In oneembodiment feeds of both solids and liquids are fed to the reactorseparately through different inlets. Solid feeds can include at leastone of an oil sand, an oil shale, a sand, as well as other solids orsemi-solids which can include coal, coke and very heavy oils, whetherseparately or in mixtures. The liquid feeds can include bitumen,kerogen, heavy oil, viscous hydrocarbon containing material, whetherseparately or in mixtures. Feedstocks to the invention can essentiallybe any hydrocarbon bearing material. Gases can also be feedstocks. Inone embodiment a hydrogen containing gas is fed to the reactor.Hydrocarbon containing gases can also be fed to the reactor in anembodiment.

“Fluidizing medium” refers to the flow stream which serves to fluidizethe bed. In one embodiment the fluidizing medium is a hydrogen feedstream.

“Reaction process” refers to the chemical and physical activitiesoccurring in the reactor including, but not limited to, the reactionbetween hydrogen and various foods, the physical agitation orfluidization of the reactor contents by the flow of hydrogen and othergases, the separation of gases and solid particles, etc.

The invention can now be described with reference to the figures. FIG. 1is a flow chart to one embodiment of the present invention where oilsand (tar sand) is converted to oil. In accordance with the presentinvention, oil sand (tar sand) from the run of mine conveyor belt 101 iscontinuously fed to any suitable sizing equipment 102 for classifyingoil sand (tar sand), at a temperature of about 50° F. Oil sand (tarsand) is composed of bitumen and sand.

The bitumen in the oil sand (tar sand) that is processed in the presentinvention normally contains heavy metals which catalytically helppromote the endothermic and exothermic reactions in reactor 104.However, it can be advantageous to add additional catalyst for reasonsincluding reduced reaction time, reduced residence time requirement inthe reactor, promote a greater degree of reaction completion, Theseactivities lead to improved performance and more efficient operationsresulting in economic benefits.

Endpoints of ranges are recognized to incorporate within their toleranceother values within the knowledge of one of ordinary skill in the art,including, but not limited to, those which are insignificantly differentfrom the respective endpoint as related to this invention (in otherwords, endpoints are to be construed to incorporate values “about” or“close” or “near” to each respective endpoint). The range and ratiolimits, recited herein, are combinable. For example, if ranges of 10-200and 50-150 are recited for a particular parameter, it is understood thatranges of 10-50, 10-150, 50-200, or 150-200 are also contemplated.

The oil sand (tar sand) processed in accordance with the presentinvention is exemplified by the following, non-limiting example:

Oil Sand (Tar Sand) Feed Example

-   -   sand 84.6 wt. %    -   bitumen 10.4 wt. %    -   water 5 wt. %    -   carbon 83.1 wt. %    -   hydrogen 10.6 wt. %    -   sulfur 4.8 wt. %    -   nitrogen 0.4 wt. %    -   oxygen 1.1 wt. %    -   100 wt. % 100 wt. %

In the present invention dry oil sand (tar sand) having an averageparticle size of that of sand is conveyed through conduit 103 as thefeed for fluidized bed reactor 104, discussed in greater detail in FIG.2. Oil sand (tar sand) particles which are oversized are either recycledto the sizing equipment 102, or conveyed to any suitable equipment forreducing the size of the oversized feed. In the present invention, thephrase “dry oil sand (tar sand)” means, under atmospheric conditions, afriable, non-sticky, easily run of mine oil sands.

Oil sand (tar sand) is fed through pressure feeder rotary valves 104Awhich are circumferentially positioned adjacent and around the upper endof the fluidized bed reactor 104, which is described in detail greaterin FIG. 2. The rotary feeders 104A are positioned at an angle of between20 and 60 degrees relative to the vertical reactor axis in order to “fanfeed” the fluidizable sized oil sand (tar sand) into the top of thereactor 104. More uniform dispersion of the oil sand (tar sand) in thefluidized bed reactor can be obtained when three or more rotary feedvalves 104A are positioned equidistantly around the circumference of thereactor. Although three feeders 104A are preferred, the size of thereactor and the degree of fanning desired can control the number ofvalve feeders. Thus, there can be 4, 5, 6, 7 or more valve feeders usedpresent invention.

High pressure hydrogen is conveyed through lines 138 to the feeders104A, at a pressure of between 625 psig and 700 psig, preferably about635 psig, to assist in injecting, feeding and dispersing the oil sand(tar sand) into reactor 104.

The process performed in fluidized bed reaction 104 involveshydrocracking, which is an endothermic reaction, and hydrogenation,which is an exothermic reaction, which reactions are conducted to favorthe production of liquid fuels and minimize the production of gasyields. The reactor operates at temperatures within the equipment designrange of about 800° F. to about 1500° F., with one embodiment having areaction temperature of 900° F.-1200° F., and another embodiment havinga reaction temperature of about 915° F. Embodiments operating lower than900° F., and even at 800° F. are less likely for, or avoid, cracking thelarge fragments of hydrogenated bitumen in the oil sand (tar sand).

It is advantageous to conduct the endothermic hydrocracking andexothermic hydrogenating processing of oil sand (tar sand) in reactor104 in a predominantly hydrogen gas environment. The hydrogen atmospherein reactor 104 is maintained at about 600 psig by fresh make-up hydrogenconveyed through line 130 from a hydrogen plant and a hydrogen recyclestream 129 which contains cleaned-up hydrogen. The volume of recyclehydrogen to fresh make-up hydrogen is preferably at least about 26 to 1.

Advantageously all the high pressure hydrogen for the process of thepresent invention, for reaction in reactor 104 and the various heatexchange operations, is provided by the steam powered compressor 132.Compressor 132 receives fresh make-up hydrogen which is conveyed throughline 130 and recycle hydrogen which is conveyed through lines 129, 140,142, 144 and 131. Compressor 132 is powered by steam conveyed throughline 162 from direct fired heater 135.

Reactor 104 operates in a highly agitated fashion insuring almostinstant and complete reaction between the bitumen components andhydrogen. The residence or retention time of the oil sand (tar sand) inreactor 104 is about 15 minutes, but can be between 10 and 20 minutes,depending on the throughput and efficiency of the reactor process. Thepressure drop from the bottom to the top of the reactor 104 is about 35psi.

Overhead products from reactor 104 are discharged from reactor 104through cyclone separators 104C, while solids are discharged throughseparator section 104B located at the lower end of reactor 104. Thecyclones separators 104C discharge an overhead stream, e.g., gas andvapor reaction components, off-gas and product, through their upper endsinto line 110, while separated solids are discharged through the lowerends of the dip legs. The cyclone separators 104C extend about 20 feetdown into the reactor 104 and establish the bed height in the reactor104.

The hot spent oil sand (tar sand) is continuously discharged at apressure of about 635 psig and a temperature of about 800° F. throughlock hopper valving arrangement 104B in the lower end of reactor 104into line 105 which conveys the discharged material to spent sand heatexchangers 106 and 108.

The reactor overhead stream from the cyclone separators 104C isdischarged into line 110, at a temperature of about 800° F. and apressure of about 600 psig. The overhead stream discharged from thereactor 104 still contains dust and dry waste particles, and is firstconveyed through line 110 to cyclone separator 111 where solids areseparated and removed through line 150. The gaseous effluent fromseparator 111 is conveyed through line 112 to an electrostaticprecipitator 113 for the final cleanup. The cleaned overhead stream fromprecipitator 113 is removed and conveyed through line 114, and separatedsolids are discharged through line 151. Cyclone separator 111 andelectrostatic precipitator 113 are of conventional design and one ofordinary skill in the art practicing the present invention can selectsuitable devices for performing the described operation.

The cleaned stream from the precipitator 113, product, vaporouscomponents, and off gas, are conveyed to in-and-out heat exchanger 115through line 114. In the in-and-out exchanger 115 the cleaned streamfrom line 114 is brought into indirect heat exchange relationship withhydrogen being conveyed through line 133, from compressor 132, i.e.,recycle and fresh make-up hydrogen, whereby heat is transferred from thecleaned stream to the hydrogen in line 133 prior to the hydrogen streamentering the fired heater 104. The cooled and cleaned stream, products,vaporous components, off-gases, from heat exchanger 115 is dischargedinto line 116 while hydrogen is discharged into line 134 which conveysthe hydrogen to the direct fired heater 134.

The cooled stream being conveyed through line 116 is introduced intocondenser 117 and is discharged at a temperature of about 100° F. intoline 118. The vapor and gas stream from the condenser is conveyedthrough line 118 at a temperature of 100° F. and is introduced intoseparator 119 where vapors and liquid are separated and discharged.

Since the gas stream has been cooled down to about 100° F. and is stillat a pressure of 480 psig, all carbon compounds C₃ and above have beencondensed are removed from the separator 119 through flow line 155 tostorage. Sour water from the separator is discharged through flow line154. The crude oil product stream in line 155 is a mixture of naphthaand gas oils having an A.P.I. of approximately 33.5 and is a light sweetcrude. The gas stream in line 120 is conveyed to a scrubbing system,e.g., at least one amine absorption column 121 where sulfur components,e.g., hydrogen sulfide and sulfur dioxide gases, are absorbed anddischarged through line 122 and conveyed to a suitable sulfur recoveryplant. The amine absorption system 121 is described in greater detail inFIG. 5.

The only gases not absorbed and removed in absorption system 121 areunreacted recycle hydrogen and C₁+C₂ hydrocarbons which are conveyedthrough line 129 to heat exchangers 106 so that the spent oil sand (tarsand) is cooled and the recycle hydrogen and C₁+C₂ hydrocarbons isheated and discharged into line 140. The C₁ and C₂ hydrocarbons in line129 can not be absorbed nor condensed but can be recycled with theunreacted hydrogen after processing in units 141, 143 and 145 discussedhereinafter. The C₁ and C₂ hydrocarbons can reach equilibrium within thereactor 104 at about 2% and can then add to the production of crude oilper ton of oil sand (tar sand). A small offset can be the increase inthe recycle stream.

As discussed above, the spent sand from the reactor 104 is dischargedinto a succession of heat exchangers 106 and 108. The first heatexchanger 106 cools the sand from 792° F. to 400° F. using cool recyclehydrogen being conveyed through line 129. The cooled spent sand isconveyed in line 107 from heat exchanger 106 and introduced into asecond heat exchanger 108 so that the sand is cooled by cold airintroduced through line 180 from blower 181 and through line 182, beforedischarging. The air heated by the spent sand is discharged into line183 which conveys the heated air to fired heater 135 for combustiontherein. Although two heat exchangers are shown, the inventioncontemplates using more if necessary.

The heated and partial recycle hydrogen stream conveyed through line 140is introduced into cyclone 141, discharged into line 142 which conveysthe stream to precipitator 143, and then through line 144 forintroduction into exchanger 145.

FIG. 2 schematically shows the pressurized, continuously operating fluidbed reactor 204 in accordance with the present invention. Sized andscreened oil sand (tar sand) or shale are conveyed through lines 203 andfed through pressure feeder rotary valves 204A into the top of thereactor 204. A portion of the gases processed in compressor 132 (FIG.1), and heated in fired heater 135 (FIG. 1) are conveyed by line 236 andintroduced into fluidized bed reactor 204 in an upward direction tofluidize the bed of the reactor 204. Another portion of the hydrogen gasfrom line 133 is conveyed through line 237 to oil sand (tar sand) feedvalves 204A through lines 238. Another portion of the hydrogen gas feedfrom line 237 is diverted through lines 239 and injected into theseparator section 204B, at the bottom end of reactor 204. Hydrogenconveyed in lines 239 is injected into the separator section 204B ofreactor 204 through injectors which are located at the ends of flowlines 239 (not shown) and aid in heat retention in the reactor systemand spent sand discharge through line 205.

High temperature and high pressure hydrogen (make-up and recycle) afterpassing through the direct fired heater 135, is introduced into reactor204 from line 236. Reaction products and unreacted hydrogen exit thereactor through internal cyclones 204C ensuring even flow out of thereactor. Although two cyclone separators are shown, the inventioncontemplates using as many as necessary to provide even flow of productgases from reactor 204 and bed height maintenance. The hot reactoreffluent stream in line 210 is then conveyed to physical and chemicalunits, described in FIG. 1 for cleanup heat recovery and productseparation.

As discussed above with reference to FIG. 1, a portion of the freshmake-up and cleaned recycle hydrogen from the compressor is conveyed toa direct fired heater. FIG. 3 schematically shows a fired heater 335(135) that is designed to balance out the total energy to operate thereactor system. Preheated air conveyed through feed lines 383 (183) iscombusted with fuel in the radiant section of fired heater 335 (135) andelevates the temperature of the recycle and make-up hydrogen that isconveyed through line 334 (134). The fuel that is combusted is obtainedfrom the C₃ fraction, e.g. propane, or natural gas produced or purchasedfrom the described process or other sources. The hydrogen stream inlines 334 (134) has been preheated in the reactor in-out exchanger 115to approximately 750° F. Since the hydrogen stream is circulated throughthe radiant section of the heater 335 the temperature of the hydrogenstream is elevated to a temperature of about 1200° F. Circulation of thehydrogen stream through line 133, 134, exchanger 115 and fired heater335 is maintained by compressor 132 so that the 1200° F. hydrogen streamcan be introduced into reactor 104 (FIG. 1) or 204 (FIG. 2).

Waste heat from the radiant section of direct fired heater 335 isrecovered in convection section 335A (135A), 335B (135B) and 335C(135C). Steam separated in drum 360 (160) is discharged into line 361(161) and introduced into convection section 335A (135A) where the steamtemperature is raised from about 596° F. to about 800° F. After passingthrough convection section 335A (135A), the superheated, high pressuresteam is conveyed through line 362 (162) to drive the steam turbine 163.Reduced temperature and pressure steam from turbine 163 is conveyed tosteam condenser 165 and the condensate recirculated via line 166 andpump 166A The flow from pump 166A is conveyed through line 168 (368) andcombined with make-up water from line 167. The water being conveyed inline 268 is introduced into convection section 335C (135C), heated anddischarged through line 369 (169) for further processing, e.g.,deaeration.

Steam drum 360 (160) separates steam which is conveyed to radiantsection 335A (135A) through line 161 to produce superheated steam forthe turbine compressor 163.

The steam circulation loop include steam drum 360 (160), line 370 (170),recirculation pump 371 (171) and lines 372-373 (172-173) which conveysboiler water through radiant section 335B (135B) and back into drum 360(160). Water for the boiler system is provided through feed line 467(167) which flows into line 468. Line 468 is similar to flow line 168,368 which communication with line 169 through connection section 335 a(135 a) to discharge.

As discussed above, convection section 335A (135A) superheats steamwhich is conveyed through line 362 (162) to drive compressor turbine163, which drives compressor 132. Steam is generated in convectionsection 335B (135B) and make-up water and turbine condensate for boilerfeed water are preheated in convection section 335C (135C).

FIG. 4, schematically shows a compressor 432 (132) driven by a highpressure steam turbine 463 (163) to maintain circulation of gases tooperate the reactor system 104. Make-up hydrogen 430 (130) and recyclehydrogen 431 (131), at approximately 450 psig and 100° F. arepressurized by the compressor 432 (132) to approximately 670 psig and122° F. and discharged into line 133 which conveys and introduces thehigh pressure hydrogen into the in-out exchanger 115 to be furtherheated by exchange with reactor product gases.

High pressure steam in line 162, 362, at 1500 psig and 800° F. drivesthe turbine 463 (163). Exhaust steam 464 (164) is condensed in condenser465 (165), and along with make-up water 467 (167) is fed to the firedheater convection section 135C, 335C for preheating and reuse as boilerfeed water make-up.

The product separation of FIG. 1, components can be described in greaterdetail with reference to FIG. 5, which schematically shows the productseparation from the circulating gas stream and removal of acid gasses inan amine system. Partially cooled reactor effluent gases 516 (116) fromthe in-out exchanger 115 are further cooled in product condenser 517(117) and conveyed through line 518 (118) to separator 519 (119) wherecondensed liquids are removed as product raw crude 555 (155). Overheadgases are conveyed through line 520 (120) to an amine absorber 5A (121)where acid gasses H₂S, CO₂ and SO₂ are absorbed by a counter currentcirculating amine solution. The recycle gases 5B flow from the top ofthe absorber 5A to recycle hydrogen stream 129.

The rich amine solution 5C exits the bottom of the absorber, flowsthrough an amine exchanger 5D where it is heated by exchange with hotstream amine solution 5L and enters the top of an amine stripper 5F.Absorbed acid gases are stripped from the amine solution by theapplication of heat to the solution in reboiler 545 (145) and areconveyed through flow line 522 (122) from the stripper to sulfurrecovery off-site. Hot recycle gases are conveyed through line 544 (144)from the spent sand cooler 145 to provide heat for reboiler 545 (145)and the partially cooled recycled gases 5G are further cooled by cooler5H and then flow through line 531 (131) to the suction side ofcompressor 132.

Lean amine solution 5J is circulated by amine circulation pumps 5Kthrough the amine exchanger 5D and amine cooler 5N to the top of theamine absorber 5A to repeat the gas cleanup process.

EXAMPLE 1

The overall mass balance for the process according to the presentinvention is shown in FIG. 6, where 1000 tons/br of oil sand (tar sand)at 50° F. are reacted with hydrogen to produce 665 bbl/r of syntheticcrude oil. The following Table provides the feed and product values forprocessing 1000 tons/hr. of oil sand (tar sand). RAW MATERIALS PRODUCTS1000 TONS/HR. OIL SAND (TAR SAND) 665 BBL/HR SCO 1.6 MMSCF/HR HYDROGEN5.2 MMSCF/HR STACK GAS 3.3 MMSCF/HR AIR 6600 LBS/HR SULFUR 0.5 MMSCF/HRNATURAL GAS 850 TONS/HR SPENT SAND REACTOR DIMENSIONS AND MASS ANDENERGY BALANCES REACTOR 104 Column Diameter 20.00 ft Cross Section Area34.16 ft. sup. 2 Void Fraction 0.85 (At Fluidization) Cross Section ofSand 47.12 ft. sup. 2 Cross Section of Gas 267.04 ft.sup.2 ReactorVolume 27394.26 ft. sup. 3 Bed Diameter 20.00 ft Bed Height 87.20 ftTime-Space Constant 0.25 hr Pressure Drop 35.00 psi OIL SAND (TAR SAND)FEED Sand Flow Rate 1000.00 tons/hr Density of sand 21.68 lbs./ft. sup.3 Volumetric sand flow 16436.55 ft. sup. 3/hr Sand Velocity 5.81ft/minute Hold-up 15.00 minutes HYDROGEN Hydrogen Flow Rate 238661.44lbs/hr (45226343 SCF/hr) Cp of H₂ 3.50 btu/lb-° F. (@ 900° F.) HydrogenRecycle Ratio 26.52 Hydrogen Flow Rate 45.28 SCF/hr Hydrogen velocity3.02 ft/s OFF GAS Gas Production 0.40 MMSCF/hr MW 30.30 g/mole Cp offlue gas 0.55 btu/lb-° F. OFF GAS COMPOSITION CO 0.30% CO₂ 0.20% H₂S31.00% NH₃ 2.50% C₃ 66.00% ENERGY BALANCE OVER-ALL CONSIDERATIONS Heatof Reaction 75.00 btu/lb. Bitumen Cp Sand 0.19 btu/ton-° F. Cp Bitumen0.34 btu/lb-° F. Cp Tarsand (sand + Bitumen) 426.70 btu/ton-° F. SandFeed Temperature 50.00° F. Sand temperature 50.00° F. at reactor inletReaction temperature 800.00° F. Sand Feed 1,000.00 tons/hr OIL SAND (TARSAND) REACTOR REACTOR CONDITIONS Heat required in reactor 356.03MMbtu/hr Heat generated in Reactor 22.50 MMbtu/hr Additional HeatRequired 335.24 MMbtu/hr Minimum H₂ for reaction 9000.00 lbs./hr (1.71MMSCF/hr) Additional H₂ Supplied 229736.15 lbs./hr (43.53 MMSCF/hr)Total H₂ Supplied 238736.15 lbs./hr (45.24 MMSCF/hr) C₁-C₂ Flow withinH₂ Stream 4594.72 lbs/hr (at equilibrium-2%) (0.08 MMSCF/hr) Entering H₂Temperature 1200.00° F. Cp H₂ 3.50 btu/lb-° F. Heat Supplied by C₁-C₂1.01 MMbtu/hr Heat Supplied by H₂ 334.23 MMbtu/hr H₂ Recycle ratio 26.53REACTOR BOTTOMS COOLER: Assures Efficient Removal of Exiting Solids ColdHydrogen Cooler Stream 1,148.68 lbs./hr (0.22 MMSCF/hr) Heat Removed2.73 MMbtu/hr Entering Hydrogen Temperature 121.64° F. Exiting SandTemperature 791.60° F. SAND COOLER SAND Sand Flow Rate 850.00 tons/hrTemperature of Entering Sand 791.60° F. Temperature of Spent Sand180.00° F. Cp Sand 0.19 btu/lb-° F. Heat Removed 198.59 MMbtu/hrHYDROGEN COOLANT FLOW Hydrogen Flow 238736.15 lbs/hr (45.24 MMSCF/hr)Heat to Be Removed 182.96 MMb/hr Entering Hydrogen Temperature 100.00°F. Exiting Hydrogen Temperature 318.96° F. AIR COOLANT Air Required forCombustion 250000.00 lbs/hr (3.27 MMSCF/hr) Cp Air 0.25 btu/lb-° F.Entering Air Temperature 50.00° F. Exiting Air Temperature 300.00° F.Heat Removed 15.63 MMbtu/hr AMINE REBOILER HYDROGEN SUPPLY EnteringHydrogen Temperature 318.96° F. Exiting Hydrogen Temperature 100.00° F.AMINE BOIL-OFF Heat Available to the system 182.96 MMbtu/hr IN-OUT HEATEXCHANGER HYDROGEN TO BE HEATED Hydrogen Flow 238736.15 lbs/hr (45.24MMSCF/hr) Inlet H₂ Temperature 121.64° F. Exiting H₂ Temperature 750.00°F. Total Heat Required 525.05 MMbtu/hr OFF GAS HEAT SUPPLY Off Gas flowrate 31978.89 lbs/hr 0.40 MMSCF/hr Condensables in vapor phase 214941.75lbs/hr MW 30.30 lb/lb-mole Cp Vapor 0.55 btu/lb-° F. Cp Liquid 0.45btu/lb-° F. Cp Non-Condenses 3.00 btu/lb-° F. Heat of Vaporization 65.00btu/lb Hydrogen Recycle Flow 229736.15 hrs/hr in Stream (*43.53MMSCF/hr) Inlet Temperature 800.00° F. Exit Temperature 350.00° F.PRODUCT CONDENSER/COOLER PRODUCT SIDE Entering Temperature 350.00° F.Exiting Temperature 100.00° F. Condensate 24941.75 lbs/hr (665.29bbl/hr) Heat Removal H₂ 201.02 MMbtu/hr Off Gas 4.40 MMbtu/hr Condensate38.15 MMbtu/hr Total 243.57 MMbtu/hr COOLER REQUIREMENT 243.57 MMbtu/hrCOMPRESSOR HYDROGEN SIDE Flow Rate 755412.69 SCF/min (45.32 MMSCF/hr)Pressure Out 670.00 psig Pressure In 450.00 psig DP 220.00 psi gamma(Cp/Cv) 1.40 # Stages 3 Temperature InIet 100.00° F. Mechanic Efficiency0.80 * 100% Pb/Pa 1.14 Power Requirement per Stage 6366.67 hp TotalPower Required 19100.00 hp Outlet Temperature 121.64° F. STEAM SUPPLYPressure 1500.00 psig Temperature 800.00° F. Degree Superheat 200.00° F.Saturation Temperature 596.20° F. Steam Heat Vue 1364.00 btu/lb FlowRate 10894.28 lbs/hr FIRED HEATER PRODUCTS TO BE HEATED HydrogenFlowrate 238736.15 lbs/hr (45.24 MMSCF/hr) Hydrogen Temperature 750.00°F. Water Flow Rate 10894.28 lbs/hr Water Temperature 75.00° F. Heat Duty517.83 MMbtu/hr C₃ ′S (FUEL PRODUCED BY THE PROCESS) Flow Rate 4263.85lbs/hr (0.04 MMSCF/hr) Heat of Combustion 20000.00 btu/lb Cp 0.60btu/lb-° F. Temperature in 75.00° F. Heat Supplied (After temperaturecorrection) 79.84 MMbtu/hr MAKE-UP METHANE Combustion Temperature2200.00° F. Heat Remaining to 437.99 MMbtu/hr be supplied by MethaneFlow Rate 21653.89 lbs/hr (0.51 MMSCF/hr) Heat of Combustion 20227.00btu/lb (After temperature correction) Temperature in 75.00° F.COMBUSTION AIR Air Required for Combustion 200000.00 lbs/hr (2.61MMSCF/hr) Air Supplied 25% Excess 250000.00 lbs/hr (3.27 MMSCF/hr)COMPRESSOR SUCTION COOLER (5H) OUTFLOWS Hydrogen Flowrate 200000.00lbs/hr Temperature 100.00° F. Required Coolant Supply 22.42 MMbtu/hrMATERIAL BALANCE OIL SAND (TAR SAND) REACTOR (104) IN FLOWS SandFlowrate 1000.00 tons/hr Temperature 50.00° F. Pressure 14.70 psia(Force Fed) Hydrogen Flowrate 45.23 MMSCF/hr Temperature 1200.00° F.Pressure 635.00 psig C₁-C₂ s Flowrate 0.08 MMSCF/hr Temperature 1200.00°F. Pressure 635.00 psig OUT FLOWS Sand Flowrate 850.00 tons/hrTemperature 190.00° F. Pressure 600.00 psig Off Gas Flowrate 43.92MMSCF/hr Temperature 800.00° F. Pressure 600.00 psig Composition wt % H₂81.98 CO 0.05 CO₂ 0.04 H₂S 5.60 NH₃ 0.45 C₃ 11.92 Product Flowrate214937.52 lbs./hr (Vapor Phase) Temperature 800.00° F. Pressure 600.00psig SAND COOLER (106, 108) IN FLOWS Sand Flowrate 850.00 tons/hrTemperature 791.92° F. Pressure 600.00 psig Hydrogen Flowrate 45.23MMSCF/hr Temperature 100.00° F. Pressure 500.00 psig Air Flowrate 3.27MMSCF/hr Temperature 50.00° F. Pressure 30.00 psig OUT FLOWS SandFlowrate 850.00 tons/hr Temperature 200.00° F. Pressure 480.00 psigHydrogen Flowrate 45.23 MMSCF/hr Temperature 313.94° F. Pressure 480.00psig Air Flowrate 3.27 MMSCF/hr Temperature 300.00° F. Pressure 20.00psig IN-OUT HEAT EXCHANGER (115) IN FLOWS Hydrogen Flowrate 45.23MMSCF/hr Temperature 147.60° F. Pressure 670.00 psig Off Gas Flowrate43.92 MMSCF/hr Temperature 800.00° F. Pressure 600.00 psig Compositionwt % H₂ 81.98 CO 0.05 CO₂ 0.04 H₂S 5.60 NH₃ 0.45 C₃ 11.92 ProductFlowrate 214937.52 lbs./hr (Vapor Phase) Temperature 800.00° F. Pressure600.00 psig OUT FLOWS Hydrogen Flowrate 45.23 MMSCF/hr Temperature750.00° F. Pressure 650.00 psig Off Gas Flowrate 43.92 MMSCF/hrTemperature 368.63° F. Pressure 580.00 psig Off Gas Composition as AboveProduct Flowrate 214937.52 lbs./hr (Vapor Phase) Temperature 368.63° F.Pressure 580.00 psig PRODUCT CONDENSER/IN FLOWS COOLER (117) Off GasFlowrate 43.92 MMSCF/hr Temperature 368.63° F. Pressure 580.00 psig OffGas Composition as Above Product Flowrate 214937.52 lbs./hr (VaporPhase) Temperature 368.63° F. Pressure 550.00 psig OUT FLOWS Off GasFlowrate 43.92 MMSCF/hr Temperature 100.00° F. Pressure 540.00 psig OffGas Composition as Above Product Flowrate 214937.52 lbs./hr (ascondensate) Temperature 100.00° F. Pressure 540.00 psig AMINE SYSTEM(121, FIG. 5) IN FLOWS Hydrogen Flowrate 45.23 MMSCF/hr Temperature318.00° F. Pressure 470.00 psig OUT FLOWS Hydrogen Flowrate 45.23MMSCF/hr Temperature 100.00° F. Pressure 450.00 psig

EXAMPLE 2

FIG. 7 shows another embodiment of the present invention. In thisembodiment, a oil sand (tar sand) feed is converted into a syntheticcrude oil. Run of mine oil sand (tar sand) from trucks is dumped intoreceiving, screening, and sizing equipment 702 for classifying oil sand(tar sand) at ambient temperature. The oil sand (tar sand) comprisesbitumen and sand. The oil sand (tar sand) is crushed into relativelylarge fluidizable pieces that are capable of passing through a one inchmesh, or that are about one inch or less in size. In this embodiment,crushing the oil sand (tar sand) into fines or pieces less than sandsize is preferably avoided to facilitate fines removal from the productstream. Limiting the amount of crushing can also reduce heat generationthat can adversely affect oil sand (tar sand) processing. Oil sand (tarsand) pieces typically comprise an agglomeration of sand particles, eachsand particle surrounded by a film of water and an outer layer ofbitumen. On contacting a hot fluidizing flow of hydrogen during laterreaction steps, the water film can rapidly evaporate assisting the oilsand (tar sand) pieces to disintegrate into a finely fluidizeddispersion of sand particles and bitumen in hydrogen.

The crushed oil sand (tar sand) is conveyed through conduit 703 to feedlock hoppers 704 as the feed for fluidized bed rector 705. The feed flowthrough conduit 703 and between feed lock hoppers 704 is controlled byball valves (“ball valves”) 703A. The bitumen in the oil sand (tar sand)can contain heavy metals, such as nickel, which can catalyticallypromote endothermic and exothermic reactions in reactor 705. Howeversupplemental catalyst such as, for example, nickel, cobalt andmolybdenum can be added through catalyst feed conduit 704A to one of thefeed lock hoppers 704 to assist catalysis provided by the heavy metalsin the mined oil sand (tar sand) or shale. The reactor 705 and relatedequipment are shown in more detail in FIG. 8.

Recycle hydrogen in conduit 725 and fresh make-up hydrogen in conduit725A are conveyed to compressor 732. A first mixture of recycle hydrogenand makeup hydrogen exits compressor 732 in line 733, is cooled by heatexchanger 754, passes through line 757 to feed lock hoppers 704. Thiscooled first hydrogen mixture helps to prevent the oil sand (tar sand)from gumming by keeping the oil sand (tar sand) cool and forces thecrushed oil sand (tar sand) into the reactor 705 which operates at apressure of about 600 psig. Preferably, the first hydrogen mixturereaches the lock hoppers 704 at a temperature of about 100° F. or less,and maintains the oil sand (tar sand) at a temperature of about 100° F.or less. The oil sand (tar sand) is fed from feed lock hoppers 704through conduit 704B and into reactor 705 through a feed inlet 705H,assisted by the first hydrogen mixture at 670 psig pressure in line 757.There are three feed lock hoppers in this embodiment, but the number canvary in other embodiments. The oil sand (tar sand) can be fed into therector approximately horizontally, near the bottom of the reactor, andjust above ceramic grid 705C. Equipment for treating mined oil sand (tarsand) or shale feed material and for feeding the material into reactor,such as the equipment described above, can be referred to as a feedintroducing system. Equipment for feeding oil sand (tar sand) or shalefeed material into the reactor, such as the feed lock hoppers 704,conduit 703 and ball valves 703A, can be referred to as a feeder device.

On entering the reactor 705, the oil sand (tar sand) is contacted andheated by a second hydrogen mixture. The second hydrogen mixture flowsfrom fired heater 735 and into a gas inlet 7051 at the bottom of thereactor 705B through ceramic lined conduit line 736 at a temperature ofabout 1500° F. and about 635 psig pressure. The second hydrogen mixturepasses through a slotted fire brick or ceramic grid 705C beforecontacting the entering oil sand (tar sand). The flow rate and velocityof the second hydrogen mixture are sufficient to fluidize the oil sand(tar sand) and to heat the oil sand (tar sand) to a desired reactiontemperature. The heated oil sand (tar sand) and the second hydrogenmixture react in the reactor 705 in a fluidized bed 705E at the desiredreaction temperature of about 900° F. to about 1000° F., and at apressure of about 600 psig. The second hydrogen mixture flow ratetypically exceeds the minimum needed for complete oil sand (tar sand)reaction with hydrogen by a factor of about 15 to about 26, andpreferably by a factor of about 21. Adjustment of the second hydrogenmixture flow rate can require adjustment of other reaction parameters tomaintain the fluidized bed 705E at desired pressures and temperatures.The oil sand (tar sand) reacts with the hydrogen mixture in thefluidized bed 705E by endothermic hydrocracking and exothermichydrogenating reactions. Reaction products include substantiallysulfur-free hydrocarbon that are condensable into hydrocarbon liquids atstandard temperature and pressure.

Reaction products including synthetic crude oil and unreacted hydrogenmixture exit the reactor 705 through a product stream outlet 705F as anoverhead or product stream through cyclone separators 705A and into exitconduit line 710. Solids entrained in the overhead product stream, suchas sand particles and fines, are trapped by the cyclone separators 705Aand are deposited near the ceramic screen 705C at the bottom of thereactor 705B, where they are again entrained in the fluidized bed 705E.Eventually, the spent sand and solids exit the reactor 705 through aconduit line 705D. The overhead stream flows through a hydrogenrecycling system wherein hydrogen is removed from the remainder of theoverhead stream, treated, and returned to the reactor.

It is advantageous to conduct the endothermic hydrocracking andexothermic hydrogenation reactions in a predominantly hydrogen gasenvironment. The first and second hydrogen mixtures are mixtures offresh make-up hydrogen and recycle hydrogen which are fed to acompressor 732 via conduit lines 725A and 725 respectively. The recyclehydrogen contains hydrogen and up to 5 mole percent of combined methaneand ethane. The amount of combined methane and ethane in the recyclehydrogen is maintained by a purge in a hydrogen recycle system connectedto the reactor 705. The volume of recycle hydrogen to fresh make-uphydrogen is preferably about 21:1, but can vary from about 15:1 to about26:1.

The reactor 705 is operated so as to highly agitate the reactants andensure rapid and complete reaction between the bitumen components andhydrogen in the reactor 705. The residence or reaction time of the oilsand (tar sand) in reactor 705 is about 10 minutes, but can be between 5and 20 minutes, depending on the throughput and efficiency of thereactor process. The pressure drop from the bottom to the top of thefluidized bed 705E is about 35 psi.

Spent sand, at a temperature of about 950° F., overflows from reactor705 into conduit line 705D through a spent solids outlet 705G. Theheight of the conduit line 705D can establish the maximum height of thefluidized bed 705E. The sand then flows through spent sand lock hoppers706, through conduit line 707 and into rotary coolers 708 which cool thesand from a temperature of 950° F. to about 665° F. The cooled sand canbe discharged and used, for example, for land reclamation.

The rotary coolers 708 can use ambient air fed through air intake 778 tocool the spent sand. The air exits the rotary coolers 708 through line779 at a temperature of about 625° F. and passes through a cyclone 780to remove entrained fines. The fines are discharged through conduit line785. The cooling air is heated by the spent sand, then passes to thefired heater 735 via blower 782 and conduit lines 781 and 783 where theair is used as preheated combustion air.

The number of feed lock hoppers 704 and spent sand lock hoppers 706 iscontrolled by the size of the reactor, thus more or less than the threefeed lock hoppers 704 and more or less than three spent sand lockhoppers can be used in the present invention.

The reactor overhead stream from the cyclone separator 705A isdischarged into line 710, and then to hot gas clean-up 711. The overheadstream in line 710 exits the reactor 705 at about 950° F. and enters thehot gas clean-up 711. Ceramic bag collectors or filters in the hot gasclean-up 711 remove and collect fines remaining in the overhead stream.The filters are periodically pulsated by a back flow of a 670 psig, 875°F. hydrogen mixture taken from in-out heat exchanger 715 via conduitline 734A. Collected fine and solids are removed from the bottom of thehot gas clean-up 711 and are collected in hot gas clean-up lock hoppers712. The fines can be combined with spent sand and used for landreclamation. The disposal of the dry sand and fines resulting from thisinvention is environmentally preferable to existing wet disposalsystems.

The substantially solids-free overhead stream flows from the hot gasclean-up through line 713 to the in-out heat exchanger 715. The in-outheat exchanger 715 is an indirect heat exchanger wherein heat istransferred from the overhead stream to a portion of the hydrogenmixture exiting compressor 732 via conduit 733. The heated hydrogenmixture is conveyed via a conduit line 734 to the fired heater 735. Thecooled overhead stream exits the in-out heat exchanger 715 through line716.

The overhead stream in line 716 enters condenser 717 where condensablevapors and gases are condensed. The overhead stream exits the condenser717 in line 718 at a temperature of about 100° F. and passes to a firstseparator 719 where sour water is purged from the overhead stream vialine 786.

The partially cooled overhead product stream in line 716 enterscondenser 717 where condensable vapors and gasses are condensed. Thecooling medium can be circulated cooling water from an on-site coolingtower. Condensed liquids and the non-condensable gases at about 100° F.flow via line 718 to a separator 719 where water is separated from thecondensed product liquids and gas stream. The amount of sour waterproduced varies depending upon the water content of the feed materialsbeing processed in the reactor 705. Any entrained oxygen in the reactorfeed is converted to water in the predominately hydrogen atmosphere inthe reactor. The waste water exits the separator 719 via line 786 and istreated to conform to environmental requirements. Stream 723 is fed toabsorber 724.

The condensed liquid product from separator 719 flows via conduit line720 to the letdown vessel 721 where pressure reduction takes place anddissolved light gases, methane and ethane, are flashed off. The flashedoff gases are conveyed via conduit line 722 to the fuel system of thefired heater 735 for combustion. The liquid hydrocarbon products areremoved from let-down tank 721 via flow line 790 as a light low sulfur(about 0.1 to 0.5 wt. % sulfur, or less) synthetic crude oil productstream which in one embodiment includes a mixture of naphtha and gasoils having on API gravity of approximately 30° to 34°. As discussedearlier, the quality of the product SCO including sulfur content can bemodified by altering process variables and the inclusion ornon-inclusion of various catalyst formulations to suit the requirementsof the refiner.

The crude oil product in line 790 can be sent directly to storagewithout further treatment or it can be sent to a hydrotreater forfurther upgrading to reduce sulfur content to 0.1 wt. % and improve APIgravity to about 34°.

The absorber 724 can comprise, for example, a counter currentcirculating ethanol amine solution in intimate contact with theremaining overhead stream. The remaining fluid stream can comprise gasessuch as, for example, H₂S, CO₂, recycle hydrogen, and C₁ and C₂hydrocarbons. H₂S and CO₂ are removed from the remaining fluid stream bythe absorber 724. Remaining hydrogen, C₁ and C₂ hydrocarbons form therecycle hydrogen mixture and flow through line 725 to compressor 732.

The rich amine solution having absorbed H₂S, CO₂, SO₂ and NH₃ isdischarged from the absorber 724 through line 740 and flows through anamine heat exchanger 741. In the amine heat exchanger 741 the rich aminesolution is heated by exchange with hot amine solution in line 750 whichis returning from amine regenerator 743 to the absorber 724. The heatedrich amine solution flows through line 742 and enters the top of theamine regenerator 743. Absorbed acid gases are stripped from the richamine solution by further heating the rich solution using steam from asteam reboiler 745. Heat for the reboiler 745 is supplied by steam fromthe fired heater 735 steam recovery system.

Lean amine solution is discharged from the regenerator 743 in line 748and is circulated by an amine circulation pump 749 through amineexchanger 741 and amine cooler 752 to the top of the amine absorber 724.

Recycle hydrogen, and C₁ and C₂ hydrocarbons flow through line 725 tocompressor 732 and are mixed with make up fresh hydrogen in line 725A ata pressure of 450 psig and a temperature of about 100° F. The recyclegas stream is also at a pressure of 450 psig, which is the lowestpressure in the system. The compressor 732 is driven by a high pressuresteam turbine 763. High pressure steam supply in line 762 comes from thefired heater steam fired heater 735. Exhaust steam in line 764 iscondensed in condenser 765 and along with make up water is fed to thefired heater 735 for preheating and reuse as boiler feed water make up.

The compressor 732 pressurizes the recycle hydrogen mixture and make-uphydrogen from 450 psig to approximately 670 psig and 187° F. anddischarges the hydrogen mixture into line 733. A portion of the hydrogenmixture in line 733 is the first hydrogen mixture and is delivered toheat exchanger 754 via line 733A. Another portion of the hydrogenmixture in line 733 is the second hydrogen mixture and is delivered tothe in-out heat exchanger 715.

The heat exchanger 754 cools the first hydrogen mixture from about 187°F. to 100° F. A portion of the first hydrogen mixture in line 757 flowsinto line 756 and to a C₁ and C₂ hydrocarbon pressure swing adsorption(“PSA”) system 755. The PSA system helps to maintain the C₁ and C₂hydrocarbon level in the first and the second hydrocarbon mixture atabout 2 vol %-3 vol %, or 2 vol %-6 vol %, also 6 vol %-8 vol % can beexperienced. C₁ and C₂ hydrocarbon purged from the first hydrocarbonmixture is discharged through line 758 and combined with the gas in line22 which is delivered to the fired heater 735. Purified hydrogenproduced by the PSA 755 flows through line 756A and back to the suctionof compressor 732 via line 725.

The second hydrogen mixture is preheated to 875° F. in the in-out heatexchanger 715 by the overhead stream at 935° F. Preheated air conveyedthrough feed line 783 is combusted with fuel in the fired heater 735 andelevates the temperature of the second hydrogen mixture that is conveyedthrough line 734 from in-out heat exchanger 715. The fuel that iscombusted is obtained from the natural gas line 759 and purge gas line722. The hydrogen mixture circulates through the fired heater 735 andexits through line 736. The second hydrogen mixture provides the heat tomaintain reaction in the reactor 705.

Waste heat from the radiant section of direct fired heater 735 isrecovered in convection sections 735A, 735B and 735C. Steam and waterare discharged from a steam drum 760 into the fired heater 735. Steamand water is returned to the drum via line 773. Steam separated fromwater in drum 760 is discharged into line 761 and introduced intoconvection section 735A where the steam temperature is raised from about596° F. to about 800° F. After passing through convection section 735A,the superheated, high pressure steam is conveyed through line 762 todrive the steam turbine 763. Reduced temperature and pressure steam fromturbine 763 is conveyed to steam condenser 765 and the condensaterecirculated via line 767. The flow from pump 766A is conveyed throughline 767 and combined with make-up water. The water being conveyed inline 767 is introduced into convection section 735C, heated anddischarged through line 736 for further processing, such as deaeration.

The following Table shows material flows and operating conditions anoperating reactor system. FLUIDIZED BED REACTOR: Reactor (fluidized bed)Temperature 950° F. Reactor (fluidized bed) Pressure 600 psig H₂ RecycleRatio 21.09 Catalyst Flow Rate into Reactor 1255.07 lbs/hr Oil sand (tarsand) Flow into Reactor 2520 tons/hr Oil sand (tar sand) Feed InletTemperature 50° F. Hydrogen Mixture Flow Rate into Reactor 60.4 MMSCF/hrHydrogen Mixture Gas Inlet Temperature 1500° F. ROTARY COOLERS: AirTemperature at Intake 50° F. Air Temperature (exiting) 623° F. SandEntering Temperature 950° F. Sand Exiting Temperature 665° F. IN-OUTHEAT EXCHANGER: Overhead Stream Entering Volumetric 58.31 MMSCF/hr FlowRate Overhead Stream Entering Temperature 950° F. Overhead StreamExiting Temperature 516° F. Hydrogen Mixture Entering Flow Rate 60.4MMSCF/hr Hydrogen Mixture Entering Temperature 185° F. Hydrogen MixtureExiting Temperature 875° F. FIRED HEATER: Fuel Consumption (natural gasequivalent) 1.2 MMSCF/hr Vapor Let-Down & PSA Off Gas Fuel Supply 0.56MMSCF/hr (natural gas equivalent) Make-up Fuel Supply 0.64 MMSCF/hrCombustion Air Entering Flow Rate 26.59 MMSCF/hr (@ 65% excess) SteamProduction Rate (@ 1500 psig) 228,996 lbs/hr Hydrogen Mixture EnteringFlow Rate 60.4 MMSCF/hr Hydrogen Mixture Entering Temperature 875° F.Hydrogen Mixture Exiting Temperature 1500° F. COMPRESSOR: Power RequiredFrom Turbine 40,148 h.p. Steam Flow Rate to Turbine 228,996.1 lbs/hrSteam Pressure Entering Turbine 1500 psig Steam Temperature EnteringTurbine 800° F. (200° F. superheat) Hydrogen Mixture Entering Flow Rate60.7 MMSCF/hr Hydrogen Mixture Compressor Entering 100° F. TemperatureHydrogen Mixture Compressor Entering 450 psig Pressure Hydrogen MixtureCompressor Exiting 185° F. Temperature Hydrogen Mixture CompressorExiting 670 psig Pressure PRODUCT CONDENSER/SEPARATOR: Product FluidStream Entering Flow Rate 58.3 MMSCF/hr Product Fluid Stream EnteringTemperature 516° F. Recycle Hydrogen Mixture Exiting 100° F. TemperatureSynthetic Crude Oil Flow Rate 1255 bbl/hr AMINE SYSTEM: AmineRecirculation Flow Rate 50,400 lbs/hr Ammonia Production 1478 lbs/hrElemental Sulfur Production 17260 lbs/hr

One aspect of the invention is the ability to process various feedstocks(feeds) having hydrocarbon content. Examples of feedstock alternativesand example combinations in which they are present are provided in Table1: In Table 1, the alternative feedstocks are shown to posses at leastthe components indicated as “X” in each respective alternative. Thealternative feed components included in Table 1 include bitumen, oilsand, sand, raw kerogen oil and oil shale. The feedstocks can containother compounds and are not limited to the components identified intable 1. TABLE 1 Feedstocks And Feedstock Combinations Alternative RawFeedstock Bitumen Oil Sand Sand kerogen oil Oil Shale 1 X 2 X 3 X 4 X 5X X 6 X X X 7 X X 8 X X X 9 X X 10 X X 11 X X X X 12 X X X X 13 X X X XX

The bitumen concentration of raw oil sand can vary. Whether an oil sandis considered an economically attractive feed can vary depending uponthe market value of the SCO product which can be derived from a givenfeedstock(s). The present invention can process oil sands withoutlimitation regarding bitumen content. Oil sands containing less than 8wt % bitumen are considered to be lower quality. However, the inventioncan process low grade and very poor quality oil sands. In oneembodiment, the bitumen feed to the reactor can be processedconcurrently with very low grade oil sands to produce an economicallyvaluable product. The processing range of oil sand feedstocks can havebitumen in a range from little or no bitumen to the richest depositsavailable (e.g., 0 wt % to more than 18 wt %, or higher).

The production rate of the plant can be maintained constant by adjustingthe rate of hot liquid bitumen injection via conduit 7103. Low grade oilsands would require a higher rate of SAGD or wet extraction bitumeninjection to maintain a constant production level of SCO for example,60,000 bbl/day or 30,000 bbl/day depending on plant design capacity.Bench scale (5 bbl/day-5,000 bbl/day) and pilot plant scale(5,000-30,000 bbl/day) designs producing very small or medium sizecapacities can be operated.

The invention can be built new or can be retrofitted into an existingplant. Further, in some embodiments, the operation of existing plantscan be modified to achieve the present invention.

In one embodiment, run of mine oil sand (from trucks, or othersource(s)) is dumped into receiving equipment which can includescreening and sizing equipment 7002 for classifying oil sand. The run ofmine sand (oil sand) enters the process at ambient temperature.

The oil sand is screened to remove rocks and debris which can includeboulders, stones tree trunks and other debris such as animal bones ormanmade items. The oil sand is crushed into fluidizable pieces that arein the range of ¼ to 1 inch mesh. Such pieces are oil sand pieces thatgreater than 1/4 inch and smaller than 1 inch in size. The pieces in oneembodiment are of particle sizes that would not pass through a 1/4 inchmesh screen but would fall through a 1 inch mesh screen. Smaller orlarger pieces can be used in other embodiments.

Limiting the amount of crushing (e.g., not crushing the pieces toofinely) reduces heat generation which can adversely affect oil sandfeeding to the reactor. Such limitation can avoid the build-up of heatin the material being crushed. Crushing generates heat because work isperformed on the material. Less crushing generates less heat. Heatgenerated in crushing oil sand can cause the bitumen contained in theoil sand to become more tacky and sticky. Sticky oil sand does not flowwell. It bridges in hoppers and plugs flow lines. The flow of oil sandinto the reactor can be impeded if the oil sand is too sticky.

The run of mine (optionally strip mined) oil sand provides both rawbitumen and sand.

The crushed oil sand is conveyed through conduit 7003 to feed hoppers7004 which provide the mechanical means for feeding solids at ambientatmospheric conditions into the pressurized fluid bed reactor 7005. Theoil sand is fed through a lock hopper system 7004 used for feeding thereactor 7005. Solid feed motivation is provided by injecting cool andhigher pressure hydrogen via conduit 7057 into the lock hoppers 7004.The feed flow through conduit 7003 and between feed lock hoppers 7004 iscontrolled by ball valves 7003A. The valves' interior surfaces are hardlined for handling very abrasive materials.

Upon being fed to the reactor, the oil sand is contacted with the gasphase present in the reactor. Upon contacting the gas phase present inthe reactor which includes a hot fluidizing flow of hydrogen the bitumenof the oil sand can experience a change of phase of its hydrocarboncomponent (oil sand bitumen) and/or chemical reaction with hydrogen orother hydrocarbons present in the reaction mixture. During this processcollectively termed “reaction process”, the water film of the oil sandbitumen vaporizes (in some instances vaporization is explosive) causingthe oil sand pieces to disintegrate, exposing more unreacted materialand surface area for reaction.

At the desired reactor conditions, the bitumen in the oil sand andinjected liquid feed reacts with the hydrogen by endothermichydrocracking and exothermic hydrogenation. These reactions areapproximately in balance and once the reactor feed is brought up toabout 900° F. by the hot hydrogen stream 7036 from the fired heater7035, the reactions can be self-sustaining. This is considered to resultfrom the endothermic hydro cracking reactions absorb heat, while theexothermic hydrogenation reactions produce heat. The production of heatapproximately offsets the absorption of heat and therefore the reactionsare approximately in balance with respect to heat requirements. Theendothermic and exothermic reactions, i.e., The exothermic reactionssupport the endothermic reactions resulting in self-sustainingreactions.

The vaporized and/or reacted hydrocarbons of the oil sand bitumen exitthe reactor 7005 through the reactor overheads line 7016.

The oil sand which has been processed produces spent sand which can beconsidered to be oil sands from which an amount of bitumen has beenextracted.

The spent sand exiting the reactor via 7005D and 7006 is the medium bywhich coke and heavy metals are ejected from the process and therebyavoid entering into the product SCO. The heavy metals combine with thecoke and the coke forms a light coating on the spent sand-particles.

Hydrogen is heated to about 1500° F. in fired heater 7035 and isintroduced to the reactor by conduit 7036 providing fluidization of thefluidizing medium. Hot liquid bitumen at about 300° F. (optionally fromSAGD, wet extraction operations, or other processes) is separatelyintroduced via conduit 7103 by pump 7102 to the reactor where intimatecontact with gaseous hydrogen feed to the fluidized bed occurs. Intimatecontact refers to the high likelihood of reactants being exposed tohydrogen in the reactor environment. The hot bitumen feed temperature isnot limited and can be of any temperature where the bitumen can bepumped. One embodiment employs a temperature range of about 200° F. toabout 350° F. The result of this contact is the vaporization of thebitumen feed in to gaseous bitumen which undergoes further reaction orexits the reactor through vapor overheads line 7010.

Reactor product vapors and reaction gasses exit the reactor via conduit7010 and high grade 34° API, low sulfur (about 0.1 to 0.5 wt. % sulfur,or less; one embodiment experiences about 0.2 wt. %) oil is condensedand processed downstream.

The invention can process any type of bitumen which can be fed to thereactor The invention will process a broad range of material rangingfrom raw sand which contains no bitumen to oil sand containing in excessof 18 wt % bitumen.

Another embodiment of the invention processes a bitumen feedstockincluding bitumen which has been sourced or produced from oil sandbitumen which has been extracted from under ground via in situprocesses. Another embodiment of the invention processes a bitumen feedstock including bitumen which has been sourced or produced from oil sandin situ. This production technique applies to oil sand too deep in theground to be mined by open pit mining.

Another embodiment of the invention processes a bitumen feedstockincluding bitumen which is derived from oil sand, whether in situ orpreviously mined, which has been extracted by a hot water extractionprocess before upgrading.

Another embodiment of the invention processes a bitumen feedstockincluding bitumen which is derived from oil sand, previously minedwherein the bitumen is separated from the oil sand by a hot waterextraction process.

Bitumen is also produced in situ by other thermal methods such as cyclicsteam stimulation or “huff and puff” technology. This involves injectingsteam into the deeply buried oil sands for several weeks to melt thebitumen. The steam injection is then stopped and hot bitumen is pumpedto the surface through the same well bore. The production phase betweencycles of steam injection can last for several months.

Another in situ production process for recovering heavy oil and bitumenis using hot water and saturated hydrocarbon solvent vapor (e.g., havingethane, propane or butane) in conjunction with horizontal wells tomobilize and recover viscous oil and bitumen from hydrocarbon deposits.The process involved injecting a hydrocarbon solvent into the reservoiralong with a displacement gas to mobilize the hydrocarbons in thereservoir and move them toward the production well. This can be referredto as a vapor production process.

The invention can be used to remediate any materials contaminated withhydrocarbons. For example sand, earth, soil, rocks, and other solids canall respectively be contaminated with liquid hydrocarbons. Feeding suchremediation feedstocks into the reaction will remediate the materials.Further, remediation feed could be fed alone or mixed with otherfeedstocks such as oil sand or shale.

Remediation feedstocks are not limited to solids or mixtures of liquidsand solids, liquid remediation is also possible. For example, motor oilor other liquid hydrocarbons can be blended with bitumen, or fedseparately to the reactor of the invention.

Kerogen oil can be processed by the invention the same way as bitumen.

Kerogen oil (raw or processed) can also be blended with bitumen feed andfed to the reactor.

In various embodiments of the invention, any solid feeds can be mixedand any liquid feeds can be mixed. This provides for varied blends ofsolid and liquid feed to be fed to the reactor. In some embodiments theblend compositions can be changed over time and additionally can bechanged over the course of a run in some embodiments without requiringshutdown.

Referring to FIG. 7-3, the bitumen feedstock or bitumen feedstock blendis in bitumen storage tank 7100 from which it is pumped by pump 7101 toreactor 7005. As discussed above, the bitumen fed to reactor 7005experiences vaporization and/or reaction.

In one embodiment, referencing FIG. 7-5, run of mine oil shale feed 7600and kerogen oil feed 7103 are processed in reactor 7005 in the presenceof a reactor gas phase including hydrogen.

Run of mine oil shale (from trucks, or other source(s)) is dumped intoreceiving equipment which can include screening and sizing equipment7002 for classifying oil shale. The run of mine shale (oil shale) entersthe process at ambient temperature.

The oil shale is screened and can be crushed into fluidizable piecesthat are in the range of ¼ to 1 inch mesh. The run of mine (optionallystrip mined) oil shale provides both raw kerogen oil and shale.

The crushed oil shale is conveyed through conduit 7003 to feed hoppers7004 which provide the mechanical means for feeding solids at ambientatmospheric conditions into the pressurized fluid bed reactor 7005. Theoil shale is fed through a lock hopper system 7004 be used for feedingthe reactor 7005. Solid feed motivation is provided by injecting cooland higher pressure hydrogen via conduit 7057 into the lock hoppers7004. The feed flow through conduit 7003 and between feed lock hoppers7004 is controlled by special ball valves 7003A. The valves' interiorsurfaces are hard lined (abrasion resistant) for handling very abrasivematerials.

Upon being fed to the reactor, the oil shale is contacted with the gasphase present in the reactor. Upon contacting the gas phase present inthe reactor which includes a hot fluidizing flow of hydrogen the kerogenof the oil shale can experience a change of phase of its constituents(oil shale kerogen) and/or chemical reaction. This process iscollectively termed as the “reaction process”

At the desired reactor conditions, the kerogen in the oil shale andinjected liquid feed reacts with the hydrogen by endothermichydrocracking and exothermic hydrogenation. These reactions areapproximately in balance and once the reactor feed is brought up toabout 900° F. by the hot hydrogen stream 7036 from the fired heater7035, the reactions are self-sustaining. In one embodiment, desiredreactor conditions can be a temperature of from 840° F. to 915° F., orup to 1000° F., or higher, and having pressures of about 550 psig to 635psig, or up to 700 psig.

The vaporized and/or reacted hydrocarbons of the oil shale kerogen exitthe reactor 7005 through the reactor overheads line 7001.

The oil shale which has been processed produces spent shale. The spentshale exiting the reactor via 7005D and 7006 is the medium by which cokeand heavy metals are ejected from the process and thereby avoid enteringinto the product SCO. The heavy metals combine with the coke and thecoke forms a light coating on the spent shale particles.

Hydrogen is heated to about 1500° F. in fired heater 7035 and isintroduced to the reactor by conduit 7036 providing fluidization of thefluidizing medium. Hot kerogen at about 300° F. is separately introducedvia conduit 7103 to the reactor where intimate contact with gaseoushydrogen present in the fluidized bed occurs. The result of this contactis the vaporization of the kerogen feed in to gaseous hydrocarbons whichcan undergo further reaction or exits the reactor through vaporoverheads line 7010.

Product vapors and gasses exit the reactor via conduit 7010 and highgrade 34° API, low sulfur (about 0.1 to 0.5 wt. % sulfur, or less; oneembodiment experiences about 0.2 wt. %) oil is condensed from the gasstream.

In one embodiment of the invention, kerogen oil which has been extractedfrom oil shale is processed. Alternatively, kerogen oil can be derivedfrom oil shale, whether in situ or previously mined.

The above-identified kerogen containing feedstocks can be processedseparately, or in a mixture.

Kerogen is found in oil shale. Oil shale occurs in many parts of theworld. The US contains the world's largest deposits of oil shale as wellas some of the richest in the western states of Colorado, Utah andWyoming. Large shale deposits are also found in the eastern US.

Kerogen content in shale varies but is not identified as such since itis a solid embedded in the shale. The richness of oil shale is normallyexpressed by the amount of raw oil obtained from the processing of theshale. Western shales generally yield 30 to 40 gal of raw kerogen oilper ton of shale. Eastern shales yield about 10-20 gal per ton of shale.

Kerogen containing feedstocks can be combined with bitumen and processedby the invention.

Feed lock hoppers 7004 and spend sand or shale lock hoppers 7006 feedsolid materials at ambient conditions into reactor 7005 at about 600psig pressure and to remove spent solids from the pressurized reactor7005 to ambient conditions on a continuous operating basis.Hydraulically operated special ball valves 7003A open and shut on apre-determined sequence for pressuring and depressuring the hoppers topermit solids to flow into and out of the reactor 7005 without the lossof pressure in the reactor. The number of feed lock hopper systems andspent material lock hoppers is dependant on the size and throughput ofreactor 7005.

The reactor 7005 is operated so as to highly agitate the reactants topromote rapid and intimate contact between the bitumen or kerogencomponents and hydrogen to ensure complete reaction takes place. Theresidence or reaction time of the oil sand or shale is between 3 and 15minutes depending on the throughput and efficiency of the reactorprocess which is dictated by the analysis of the various feedcomponents. The pressure drop across the fluidized bed in reactor 7005is about 25 to 40 psi.

In one embodiment, reactor 7005 contains a bed which is fluidized andwhich can include either the oil sand feed, or include other fluidizablematerials. In some embodiments having oil sand or sand as thefluidization material, the fluidized sand particles provide an inert,non-reactive carrier or base promoting contact between the hydrogen andthe liquid bitumen for reaction to take place.

Spent sand or shale from the fluid bed in reactor 7005 is displaced byincoming feed to the bottom of the reactor and overflows at the top ofthe reactor into conduit line 7005D. The height of the conduit lineabove the reactor grid 7005C establishes the maximum depth of thefluidized bed in reactor 7005. The hot spent sand or shale then flowsthrough lock hoppers 7006, through conduit line 7007 and into rotarycoolers 7008 where the solids are cooled from reactor temperature toabout 300° F. The cooler discharge 7009 can then be back hauled byconventional equipment for land reclamation or be slurried with waterand/or pumped to a settling location.

On entering the reactor 7005, oil sand or sand is contacted and heatedby the combined recycle and make-up hydrogen introduced via line 7036from the fired heater 7035. The fired heater elevates the temperature ofthe hydrogen stream to about 1500° F. at about 635 psig and afterentering the bottom of the reactor 7005B, the hydrogen passes through aslotted fire brick or ceramic grid 7005C which supports the fluid bed ofsand and aids in evenly distributing the hydrogen stream into thefluidized bed. The hydrogen flow rate and velocity of between 2 and 10ft./sec. is sufficient to fluidize the oil sand or sand bed. The hightemperature hydrogen heats the oil sand or sand from ambient to areaction temperature of about 850° F. to 925° F. at a pressure of about500 to 650 psig.

The volume of recycle hydrogen compared to fresh make-up hydrogen i.e.the recycle ratio, is a function of a number of operating variablesincluding:

-   -   Hydrogen velocity to fluidize the contents of the reactor 7005        to create a fluid bed.    -   The amount of heat to bring the oil sand, bitumen or shale feed        up to reaction temperature of about 900° F. Hydrogen is the        ideal medium by which heat is conveyed into the reactor 7005        having the highest heat capacity of any gas.    -   Temperature of the hydrogen from the fired heater 7035 in line        7036 normally heated to about 1500° F.    -   Residence time of the reactants in the reactor 7005 (reaction        time) for optimum conversion of the bitumen or kerogen to        product vapors.

The recycle ratio is preferably about 21:1 but can vary from about 5:1to about 30:1 depending upon which of the process embodiments is beingoperated. The combined recycle hydrogen and make-up hydrogen arecompressed by the high speed centrifugal compressor 7032 and dischargedinto line 7033 at a pressure of about 670 psig and 187° F. Thecompressor 7032 discharge stream is divided into two streams: a smallerstream flows via conduit line 7033A to gas cooler 7054; a much largerstream representing about 85-90 wt. % of the total discharge isdelivered to the in-out heat exchanger 7015.

The cooled hydrogen gas in line 7057 exiting from gas cooler 7054 isagain divided into two streams. The larger portion of this stream isdelivered to the reactor feed lock hopper system 7004 at about 100° F.and is used to motivate the oil sand feed through the lock hoppers 7004into the reactor 7005. When sand only or oil shale is fed, cooling ofthis motivation stream is not necessary and this gas is then by-passedaround gas cooler 7054 and used at compressor discharge conditions of670 psig and 187° F.

The smaller portion of the cooled 1001F hydrogen stream exiting gascooler 7054 representing about 6 wt. % of the recycle gas enteringcompressor 7032 flows via conduit line 7056 to the pressure swingadsorption (PSA) system 7055.

While the bitumen feed or the bitumen in the oil sand can contain heavymetals, such as nickel, which can catalytically promote endothermic andexothermic reactions in reactor 7005, supplemental catalyst, such asnickel, cobalt or molybdenum, can be added through feed conduit 7004A tofeed lock hopper 7004 to promote additional catalytic reaction. Thereactor and related equipment are shown in more detail in FIG. 8-0.

The invention can include the following unit operations: Hot gasclean-up system 7011 In-out heat exchanger 7015 Product separation 7019,7021 Hydrotreater 7200 Amine adsorption system 7400 Steam turbine 7063Hydrogen circulation compressor 7032 Pressure swing adsorption (PSA)7055 Fired heater 7035 Spent sand coolers 7008In an embodiment having these unit operations, high grade syntheticcrude oil can be produced at about 850-950° F. temperature and pressureof about 600 psig.

The recycle hydrogen 7025 and make up hydrogen 7025A from the hydrogenplant 7300 are conveyed to compressor 7032. A side stream of combinedrecycle and make-up hydrogen exits compressor 7032 via lines 7033 and7033A and is cooled by heat exchanger 7054. This cooled stream can bediscussed later since it is used in various requirements.

On entering the reactor 7005, oil sand or sand is contacted and heatedby the combined recycle and make-up hydrogen introduced via line 7036from the fired heater 7035. The fired heater elevates the temperature ofthe hydrogen stream to about 1500° F. at about 635 psig and afterentering the bottom of the reactor 7005B, the hydrogen passes through aslotted fire brick or ceramic grid 7005C which supports the fluid bed ofsand and aids in evenly distributing the hydrogen stream into thefluidized bed. The hydrogen flow rate and velocity of between 2 and 10ft./sec. is sufficient to fluidize the oil sand or sand bed. The hightemperature hydrogen heats the oil sand or sand from ambient to areaction temperature of about 850° F. to 925° F. at a pressure of about500 to 650 psig.

The hydrogen flow rate from the fired heater 7035 typically exceeds thestoichiometric requirements for bitumen conversion with hydrogen by afactor of about 5 to 30. The recycle rate is governed by many variablessuch as temperature of the solids fed to the reactor and the ratio ofoil sands or sand to hot bitumen feed. Since oil sand typically containsabout 10 wt. % bitumen and 85 wt. % sand, increasing bitumen feedinjection would require less sensible heat for a constant productionrate and hence a lower ratio of recycle hydrogen to make-up hydrogenwould be necessary.

Fresh make-up hydrogen produced on site in a conventional steam-methanereform hydrogen plant 7300 is admitted into compressor 7032 via conduitline 7025A and joins the recycle hydrogen from the amine scrubbingsystem 7400 delivered to the compressor via line 7025. Both streamsenter the compressor 7032 at about 100° F. and 500 psig.

The ambient air used in rotary coolers 7008 to cool the spent sand orshale exits the coolers at a temperature of about 625° F. via conduitline 7079. It is highly advantageous to the overall process efficiencyto use this hot air for combustion air in the fired heater 7035 and inthe hydrogen plant 7300. For this purpose, the hot air is cleansed ofentrained fines by passing through a cyclone 7080 followed by a bagcollector. The fines are discharged through conduit line 7085 to bereturned to land reclamation along with the spent sand or shale 7009.Hot combustion air blower 7082 supplies the fired heater 7035 with itsrequirements via conduit line 7083 and the hydrogen plant 7300 viaconduit line 7301.

Reaction products include hydrocarbon vapors that are condensable intohydrocarbon liquids of excellent quality in terms of API gravity, sulfurcontent, and distillation. The product is stable and in one embodimentcontains no material boiling above 975° F. It is pipe-linable andconstitutes an excellent refinery feed.

Reactor effluent gases including product vapors, excess recyclablehydrogen, methane, ethane, propane, hydrogen sulfide and water vaporexit the reactor 7005 as an overhead or product stream through cycloneseparators 7005A and into exit conduit line 7010. Solids entrained inthe overhead product stream, such as sand particles, shale and fines,are removed from the product stream by the cyclone separators 7005A andrecycled to the bottom of the reactor near the ceramic support grid7005C where they are again entrained in the fluidized contents of thereactor.

The reactor overhead stream from the cyclone separators 7005A flows vialine 7010 to the hot gas clean-up system 7011. Here the hot gas streamat about 900° F. is filtered to remove and collect any fines that haveescaped the reactor cyclone separators 7005A. The ceramic or sponge ironfilters are periodically and section by section back flushed or pulsatedby a higher pressure hydrogen flow via line 7034A from the in-out heatexchanger 7015. Collected fines and solids are removed from the bottomof hot gas filter 7011 by lock hoppers 7012 which operate in similarmanner as the lock hoppers on the reactor 7005. The fines are combinedwith spent sand or shale and used for land reclamation. The disposal ofthe dry sand or shale and fines resulting from the invention isenvironmentally preferable to existing wet disposal systems.

The filtered solids free product stream flows from the hot gas clean-upsystem through line 7013 to the in-out heat exchanger 7015. Thisexchanger is an indirect, shell and tube, heat exchanger wherein heat isrecovered from the reactor overhead product stream and transferred tothe purified recycle and fresh make-up replenished hydrogen stream beingreturned to the reactor. This heat exchange is a major part of totalprocess waste heat recovery and is vital to the overall processefficiency. The heat duty of in-out exchanger 7015 is nearly equal tothat of the fired heater 7035. The heated product free hydrogen streamis conveyed via conduit line 7034 to the fired heater 7035 foradditional heating prior to admission to the reactor. The cooledoverhead product stream exits the in-out heat exchanger 7015 throughline 7016 at about 450° F.

The PSA system 7055 utilizing resins removes the light hydrocarbons,methane and ethane, and also ammonia from the entering gas stream byadsorption of the these gases onto the resin. The purified hydrogenstream leaves the PSA system 7055 through line 7056A and flows back tothe suction of the compressor 7032 via line 7025.

When the PSA resin has reached its capacity to adsorb the undesirablegases, the stream being purified is diverted to another vessel in thesystem. The pressure is reduced in the vessel removed from service sothat it can be regenerated and returned to service later. The adsorbedC₁, C₂ and ammonia gases are removed from the resin by a hydrogen gaspurge stream which is then passed through a chiller to condense andknock out the ammonia. The ammonia is removed from the purge gas streamto avoid burning it with the fuel in the fired heater 7035 and creatingair pollutants. The PSA purge stream cleansed of ammonia is dischargedfrom the PSA system 7055 through line 7058 and combines with the flashvapors in line 7022 from the product let-down vessel 7021. These purgedand flashed off gases flow together to the fuel system for combustion inheater 7035. Purging the recycle hydrogen stream 7025 of C₁, C₂, andammonia gases is necessary to prevent their accumulation in the systemwhere they act as inerts and suppress the partial vapor pressure ofhydrogen. Purging of the system is regulated to maintain a maximumconcentration of about 6 wt. % inerts in the recycle stream.

The main compressor discharge stream of purified recycle and make-uphydrogen delivered to the in-out exchanger 7015 is heated from about187° F. to about 875° F. by exchange with the reactor overhead stream.The gas exits the in-out exchanger and flows via line 7034 to theradiant section of fired heater 7035. The temperature of the reactorfeed gas is elevated to about 1500° F. as it circulates through thefired tubes of heater 7035 and then flows via conduit line 7036 to thereactor 7005 to repeat the cycle.

Producing the hydrogen recycle involves filtration of the hot exitingvapors (e.g., 800° F. to 1000° F.) to remove particulates, acid gasremoval in an amine absorption system, removal of reaction inert gasesin a pressure swing adsorption (PSA) system and recompression of thepurified recycle stream from a high pressure level (400 psig-700 psig)to minimize energy requirements.

The hot reactor effluent vapors at about 915° F. (range 850° F. to 1000°F.) can contain entrained particles of sand or shale that have escapedthe internal cyclones. These entrained particulates have to be removedfrom the reactor effluent stream to avoid contamination of the liquidproduct that is eventually condensed down stream in the process.

The hydrogen recycle stream from the amine system and the hydrogenstream from the PSA system returning to the compressor suction forrecompression are said to have been purified by the removal of the acidgases and purging of methane and ethane.

The inlet to the compressor can have the lowest pressure in the entireprocess circuit. It is desirable to have the compressor suction pressureas high as possible relative to the compressor discharge pressure inorder to conserve energy. Less work is necessary to be performed by thecompressor if the pressure differential or pressure drop across the gascirculating system is kept as low as possible. The compressor dischargepressure is normally operated at about 670 psig and the suction pressureat about 500 psig but can go as low as 450 psig.

Heat in the combustion gases from the radiant section of the directfired heater 7035 is recovered in the convection sections 7035C, 7035Band 7035A whose function is to preheat boiler feed water, generate highpressure steam and superheat steam, respectively. Boiler feed water fromthe water treating section and condensate returned from various steamcondensing services in the plant is preheated in section 7035C and flowsto a de-aerator via line 7069 and is then pumped to steam drum 7060.Boiler water is circulated from the steam drum 7060 via line 7072 toconvection section 7035B where high pressure steam is generated in theboiler tubes by exchange with the flue gases exiting the fired heater7035. A mixture of water and steam is returned via line 7073 to theboiler drum 7060 to separate the steam from the water. Steam systempressure can be designed to suit the operator and can vary from 800 psigto 1500 psig. In this example, operating pressure was chosen to be 1500psig.

High pressure steam at 1500 psig flows from steam drum 7060 via line7061 to convection section 7035A where it is superheated from saturationtemperature 596° F. to about 800° F. providing about 200° F. ofsuperheat. The superheated steam flows via line 7062 to the high speedturbine 7063 which drives the centrifugal hydrogen compressor 7032 thatcirculates hydrogen around the process circuit. Exhaust steam fromturbine 7063 is condensed in condenser 7065 and the resulting condensateis returned to the steam system via condensate pump 7066A and line 7067for reuse as boiler feed water.

Optionally, additional heat recovery, not shown in the flow diagram, canbe achieved down stream of in-out exchanger 7015 and before thepartially cooled overhead product stream is admitted via conduit line7016 to condenser 7017. Low pressure steam can be generated for electricpower generation, driving small turbines, pumps, and heatingrequirements within the plant complex. Any waste heat recovered at thispoint is advantageous to the overall process efficiency and applies toall three embodiments of this invention.

The partially cooled overhead product stream in line 7016 enterscondenser 7017 where condensable vapors and gasses are condensed. Thecooling medium is circulated cooling water from an on-site coolingtower. Condensed liquids and the non-condensable gases at about 100° F.flow via line 7018 to a separator 7019 where water is separated from thecondensed product liquids and gas stream. The amount of sour waterproduced varies depending upon the water content of the feed materialsbeing processed in the reactor 7005. Any entrained oxygen in the reactorfeed is converted to water in the predominately hydrogen atmosphere inthe reactor. The waste water exits the separator 7019 via line 7086 andis treated to conform to environmental requirements.

The condensed liquid product from separator 7019 flows via conduit line7020 to the letdown vessel 7021 where pressure reduction takes place anddissolved light gases, methane and ethane, are flashed off. The flashedoff gases are conveyed via conduit line 7022 to the fuel system of thefired heater 7035 for combustion. The liquid hydrocarbon products areremoved from let-down tank 7021 via flow line 7090 as a light low sulfur(about 0.1 to 0.5 wt. % sulfur, or less) synthetic crude oil productstream comprising a mixture of naphtha and gas oils having on APIgravity of approximately 30° to 34°. As discussed earlier, the qualityof the product SCO including sulfur content can be modified by alteringprocess variables and the inclusion or non-inclusion of various catalystformulations to suit the requirements of the refiner.

The crude oil product in line 7090 can be sent directly to storagewithout further treatment or it can be sent to a conventionalhydrotreater 7200 for further upgrading to reduce sulfur content to 0.1wt. % and improve API gravity to about 34°. Low sulfur (about 0.1 to 0.5wt. % sulfur, or less) product from hydrotreater 7200 is storedseparately and can be used as the primary fuel in the fired heater 7035and the hydrogen plant 7300 reformer to reduce requirements for naturalgas to hydrogen production only.

In an embodiment, this process invention provides the option ofimproving product quality by either adding catalyst with the feed to thereactor 7005 to promote catalytic hydrogenation or to further upgradethe product in the plant's integrated hydrotreater 7200. Operationalflexibility is provided by these options to produce a product withbroader market appeal.

The hydrotreater 7200 receives hot hydrogen from the high pressuredischarge side of compressor 7032 via the fired heater 7035 in conduitline 7201. Relatively cool hydrogen directly from the compressordischarge is provided via conduit line 7202 for temperature controlsince the hydrotreater process is exothermic. Excess hydrogen and theacid gas, hydrogen sulfide, produced in the hydrotreater 7200 flow,after being cooled to 100° F., via conduit line 7203 to the aminescrubbing system 7400 to remove the acid gas and recycle the excesshydrogen. Economic benefits can be realized by integrating thehydrotreater into this process invention as such integration makespossible the options of:

-   -   Sharing of a common hydrogen circulation compressor 7032,    -   Sharing of a common amine scrubbing system 7400,    -   Sharing a common source of hydrogen 7300, and/or    -   Operational flexibility previously mentioned visa vie catalyst        addition to the reactor 7005.

The reactor overhead stream now free of the condensed product and watervapors and comprising of excess hydrogen, light hydrocarbon gasesmethane and ethane and acid gases exit separator 7019 via conduit line7023 at 100° F. and about 525 psig to flow to the amine scrubbing system7400. Here the stream is joined by the hydrotreater acid gas stream 7203and the combined streams enter in to the acid gas absorber column 7024.As the combined recycle gases rise up through the packed absorber column7024 a counter current flow of cold di-ethanol amine solution (DEA)absorbs the acid gases, mainly H₂S with trace amounts of CO₂ and thescrubbed recycle hydrogen along with the light hydrocarbon gases exitthe absorber to flow through line 7025 to compressor 7032.

The rich amine solution having absorbed the acid gases is dischargedfrom the bottom of the absorber 7024 via line 7040 and flows through thelean-rich exchanger 7041. Here the cold rich amine solution is heated byexchange with hot lean amine solution returning from amine regenerator7043 to the absorber 7024. The preheated rich amine solution flowsthrough line 7042 and enters near the top of amine regenerator 7043. Inthe regenerator 7043 a combination of pressure reduction and heat stripsthe acid gases from the amine solution as it descends the packed ortrayed tower. Heat is applied to the amine solution in steam reboiler7045 and with the reduction of pressure the absorbed acid gases arereleased to exit the regenerator via line 7044. The hydrogen sulfide isthen processed in a sulfur recovery plant where it is converted toelemental sulfur. The process is highly efficient recovering more than99.98 wt. % of the acid gas sulfur.

Lean hot amine solution flows from regenerator 7043 in line 7048 toamine circulation pump 7049 which pressurizes the amine solutionsufficiently to flow via line 7050 through lean-rich exchanger 7041where it is cooled by exchange with the cold rich amine solution fromthe absorber 7024. The operating principles in lean-rich exchanger 7041and in-out exchanger 7015 are similar in that energy conservation iseffected by recovering heat from streams that have to be alternatelyheated and cooled. The lean amine solution is further cooled in aminecooler 7052 and returned to the top of amine absorber 7024 via conduitline 7053 to repeat the cycle.

Optionally, the following design elements can be included in theinvention:

-   -   Integrating hydrogen plant 7300,    -   A common boiler feed water treatment system for the fired heater        7035 and the hydrogen plant reformer,    -   Combustion air is preheated in rotary sand cooler 7003 for the        fired heater 7035 and hydrogen plant reformer,    -   Fuel requirements for the fired heater 7035 and hydrogen plant        reformer can be met by the high grade low sulfur (about 0.1 to        0.5 wt. % sulfur, or less) product oil produced by this process,    -   A common cooling water system can be shared,    -   An integrated steam system is possible maximizing waste heat        recovery for power generation,    -   A common control room integrates all plant operations minimizing        manpower requirements and improves operating efficiency, and/or    -   Integration of support facilities such as administration,        operations, maintenance, etc. is possible.

While particular embodiments of the present invention have beenillustrated and described herein, the present invention is not limitedto such illustrations and descriptions. It is apparent that changes andmodifications can be incorporated and embodied as part of the presentinvention within the scope of the following claims.

Product quality can be varied by altering process variables such astemperature, pressure, reactor residence time, hydrogen recycle ratio,amount and variations in formulation of catalyst addition to the reactorfeed, etc. The product quality can be modified to more adequately meetthe requirements of a particular refiner's feed stock.

It is also possible to achieve the design of the present invention byretrofitting an existing process or facility to achieve the presentinvention.

EXAMPLE 3

Although the invention has been described in conjunction with specificembodiments, many alternatives and variations will be apparent to thoseskilled in the art in light of this description and the annexeddrawings. Accordingly, the invention is intended to embrace all of thealternatives and variations that fall within the spirit and the scope ofthe appended claims.

1. A process for producing synthetic crude oil, comprising the steps of:providing a reactor, providing a first feed stream comprising an oilsand, providing a second feed stream comprising a hydrocarbon containingliquid, providing a gas feed comprising hydrogen, contacting said oilsand and said hydrocarbon containing liquid with said hydrogen in saidreactor, producing a reactor gas stream.
 2. (canceled)
 3. The process ofclaim 1, wherein said first feed stream comprises an oil sand comprisinga bitumen in a concentration of 10 wt. % or greater. 4-12. (canceled)13. The process according to claim 1, wherein said second feed streamcomprises liquid bitumen.
 14. The process of claim 1, wherein said gasfeed comprises hydrogen in a range of 50 wt. % to 100 wt. % 15-16.(canceled)
 17. The process of claim 1, wherein said gas feed comprisesabout 10 wt. % or less of methane. 18-19. (canceled)
 20. Process ofclaim 1, wherein said gas feed comprises recycle hydrogen.
 21. Theprocess of claim 20, wherein said recycle hydrogen is heated in a rangeof about 800° F. to about 1500° F. 22-23. (canceled)
 24. The process ofclaim 1, further comprising the step of: condensing said reactor gasstream, producing a synthetic crude oil having an API gravity in therange of about 25° API to about 40° API. 25-28. (canceled)
 29. Theprocess of claim 24, wherein said synthetic crude oil has a sulfurconcentration of about 0.5 wt. % sulfur or less.
 30. (canceled)
 31. Theprocess of claim 1, wherein said process is a continuous process. 32.The process of claim 1, wherein said reactor is a fluidized bed reactor.33. The process of claim 1, wherein said contacting occurs at atemperature in a range of 850° F. to 1000° F. 34-41. (canceled)
 42. Theprocess of claim 32, further comprising the step of: providing afluidizing medium to said reactor which comprises hydrogen.
 43. canceled44. The process of claim 1, further comprising the step of: operatingsaid reactor at a temperature of about 900° F. and about 600 psig.45-47. (canceled)
 48. The process according to claim 1, furthercomprising the step of: employing a catalyst in said reactor. 49-52.(canceled)
 53. The process of 32, wherein said fluid bed reactorcomprises a fluid bed having a shale.
 54. The process of 32, whereinsaid fluid bed reactor comprises a fluid bed having a sand. 55-57.(canceled)
 58. A process for producing synthetic crude oil, comprisingthe steps of: providing a reactor, providing a first feed streamcomprising kerogen, providing a second feed stream comprising ahydrocarbon containing liquid, providing a gas feed comprising hydrogen,contacting said kerogen with said hydrogen in said reactor, producing areactor gas stream.
 59. The process of claim 58, further comprising thestep of: providing said first feed stream comprising oil shale havingkerogen.
 60. The process of claim 58, wherein said gas feed compriseshydrogen in a range of 50 wt. % to 100 wt. % 61-62. (canceled)
 63. Theprocess of claim 58, wherein said gas feed comprises about 10 wt. % orless of methane. 64-69. (canceled)
 70. The process of claim 58, furthercomprising the step of: condensing said reactor gas stream, producing asynthetic crude oil having an API gravity in the range of about 25° APIto about 40° API. 71-72. (canceled)
 73. The process of claim 70, whereinsaid synthetic crude oil has a sulfur concentration of about 0.5 wt %sulfur or less.
 74. (canceled)
 75. The process of claim 58, wherein saidprocess is a continuous process.
 76. (canceled)
 77. The process of claim58, wherein said reactor is a fluidized bed reactor.
 78. Process ofclaim 58, wherein said gas feed comprises recycle hydrogen.
 79. Theprocess of claim 78, wherein said recycle hydrogen is heated in a rangeof about 800° F. to about 1500° F. 80-83. (canceled)
 84. The process ofclaim 58, wherein said first feed stream comprises an oil shalecomprising kerogen in a concentration of 5 wt % or greater. 85-87.(canceled)
 88. The process of claim 58, wherein said second feed streamcomprises a bitumen. 89-90. (canceled)
 91. The process of claim 77,comprising a fluidizing medium which comprises hydrogen. 92-100.(canceled)
 101. The process according to claim 58, further comprisingthe step of: employing a catalyst in said reactor.
 102. (canceled) 103.The process of claim 77, wherein said fluid bed medium is shale
 104. Theprocess of claim 77, wherein said fluid bed medium is sand.
 105. Anapparatus for producing synthetic crude oil according to the process ofclaim
 1. 106. An system for producing synthetic crude oil according tothe process of claim
 1. 107. A control system for producing syntheticcrude oil according to the process of claim
 1. 108. An apparatus forproducing synthetic crude oil according to the process of claim
 58. 109.An system for producing synthetic crude oil according to the process ofclaim
 58. 110. A control system for producing synthetic crude oilaccording to the process of claim
 58. 111. A process for producingsynthetic crude oil, comprising the steps of: providing a reactor whichcontinuously reacts at least one of an oil sand or a tar sand, providinga first feed stream comprising at least one of an oil sand or a tarsand, providing a second feed stream comprising a hydrocarbon containingliquid, providing a gas feed comprising hydrogen in a range of 90 wt. %to 100 wt. % and about 10 wt. % or less of methane and about 10 wt. % orless of ethane, said gas feed further comprising recycle hydrogen,contacting said oil sand and said hydrocarbon containing liquid withsaid hydrogen in said reactor, producing a reactor gas stream,condensing said reactor gas stream, producing a synthetic crude oilhaving an API gravity in the range of about 25° API to about 40° API andhaving a sulfur concentration of about 0.2 wt. % sulfur or less.